[Federal Register Volume 78, Number 22 (Friday, February 1, 2013)]
[Rules and Regulations]
[Pages 7488-7522]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2012-31645]
[[Page 7487]]
Vol. 78
Friday,
No. 22
February 1, 2013
Part II
Environmental Protection Agency
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40 CFR Part 63
National Emission Standards for Hazardous Air Pollutants for Area
Sources: Industrial, Commercial, and Institutional Boilers; Final Rule
Federal Register / Vol. 78 , No. 22 / Friday, February 1, 2013 /
Rules and Regulations
[[Page 7488]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 63
[EPA-HQ-OAR-2006-0790; FRL-9698-5]
RIN 2060-AR14
National Emission Standards for Hazardous Air Pollutants for Area
Sources: Industrial, Commercial, and Institutional Boilers
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule; notice of final action on reconsideration.
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SUMMARY: In this action, the EPA is taking final action on
reconsideration of certain issues related to the emission standards to
control hazardous air pollutants from new and existing industrial,
commercial and institutional boilers at area sources which were issued
under section 112 of the Clean Air Act. As part of this action, the EPA
is amending certain compliance dates for the standard and making
technical corrections to the final rule to clarify definitions,
references, applicability and compliance issues raised by petitioners
and other stakeholders affected by the rule. The EPA today is taking
final action on the proposed reconsideration.
DATES: This final rule is effective on February 1, 2013. The
incorporation by reference of certain publications listed in this final
rule were approved by the Director of the Federal Register as of
February 1, 2013.
ADDRESSES: The EPA established a single docket under Docket ID No. EPA-
HQ-OAR-2006-0790 for this action. All documents in the docket are
listed on the http://www.regulations.gov Web site. Although listed in
the index, some information is not publicly available, e.g.,
confidential business information or other information whose disclosure
is restricted by statute. Certain other material, such as copyrighted
material, is not placed on the Internet and will be publicly available
only in hard copy form. Publicly available docket materials are
available either electronically through http://www.regulations.gov or
in hard copy at the EPA's Docket Center, Public Reading Room, EPA West
Building, Room 3334, 1301 Constitution Avenue NW., Washington, DC
20004. This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday
through Friday, excluding legal holidays. The telephone number for the
Public Reading Room is (202) 566-1744, and the telephone number for the
Air Docket is (202) 566-1741.
FOR FURTHER INFORMATION CONTACT: Ms. Mary Johnson, Energy Strategies
Group (D243-01), Sector Policies and Programs Division, Office of Air
Quality Planning and Standards, Environmental Protection Agency,
Research Triangle Park, North Carolina 27711; telephone number: (919)
541-5025; fax number: (919) 541-5450; email address:
[email protected].
Executive Summary
Purpose of This Regulatory Action
The EPA is taking final action on its proposed reconsideration of
certain provisions of its March 21, 2011, final rule that established
emission standards for the source category of new and existing
industrial, commercial, and institutional boilers located at area
source facilities listed pursuant to CAA sections 112(c)(3), 112(c)(6),
and 112(k)(3)(B).
Section 112(d) of the CAA requires the EPA to regulate HAP from
both major and area stationary sources. Section 112(d)(5) of the CAA
allows the EPA to establish standards for area sources of HAP ``which
provide for the use of generally available control technologies (GACT)
or management practices by such sources to reduce emissions of
hazardous air pollutants.'' While GACT serves as the basis for
standards of most emissions from area source boilers, two pollutants
emitted by coal-fired boilers, POM as 7-PAH and Hg, must be regulated
based on the performance of MACT. These two pollutants are regulated
based on MACT because area source industrial, commercial and
institutional boilers combusting coal were listed under section
112(c)(6) of the CAA due to the source categories' emissions of POM and
Hg. Section 112(c)(6) requires the EPA to regulate sources listed
pursuant to that provision by issuing standards under section 112(d)(2)
or (d)(4). The final rule meets this requirement by setting MACT
standards for Hg and CO (as a surrogate for POM) for units in the coal-
fired subcategory. Further, the final rule sets standards based on GACT
for the urban HAP, other than Hg and POM, emitted from coal-fired
boilers that pose the greatest public health risk, pursuant to section
112(c)(3) of the CAA, including arsenic, beryllium, cadmium, lead,
chromium, manganese, nickel, ethylene dioxide, and PCBs. In addition,
the final rule sets standards based on GACT for boilers combusting oil
or biomass for urban HAP, including Hg, arsenic, beryllium, cadmium,
lead, chromium, manganese, nickel, POM, ethylene dioxide, and PCBs.
In developing the MACT standards for coal-fired boilers, the EPA
considered section 112(h) of the CAA, which allows the EPA to establish
work practice standards in lieu of numerical emission limits under
section 112(d)(2) only in cases where the agency determines that it is
not feasible to prescribe or enforce an emission standard. The EPA has
set work practice standards for emissions of Hg and POM from small
coal-fired boilers, pursuant to section 112(h), in the form of periodic
tune-ups.
This final rule amends certain provisions of the final rule issued
by EPA on March 11, 2011, and responds to petitions for reconsideration
filed by a number of different entities.
Summary of Major Reconsideration Provisions
In general, the final rule requires facilities classified as area
sources of HAP with affected boilers to reduce emissions of harmful
toxic air emissions from these combustion sources, improving air
quality, and protecting public health in communities where these
facilities are located.
Recognizing the diversity of this source category and the multiple
sectors of the economy this rule affects, the EPA is establishing seven
subcategories for boilers based on the design of the combustion
equipment and operating schedules of the unit. In addition to the coal,
biomass, and oil subcategories in the March 2011 final rule, we are
establishing subcategories for seasonal boilers, limited-use boilers,
oil-fired boilers with heat input capacity of equal to or less than 5
MMBtu/hr, and certain boilers that use a continuous oxygen trim system.
Numerical emission limits, based on MACT, are established for Hg
and CO at new and existing large coal-fired boilers (i.e., with a
design heat input capacity of 10 MMBtu/hr or more). A review of the
data has resulted in changes to the Hg and CO emission limits contained
in the March 2011 final rule. The EPA is also establishing a CEMS
alternative compliance option for the numeric CO emission limit. Coal-
fired boilers subject to a CO emission limit can comply with the limit
using a periodic stack test and CPMS, or by using CEMS. The CO CEMS
alternative compliance option is based on a 10-day rolling average and
provides additional compliance flexibility to sources with existing CO
CEMS equipment. New and existing small coal-fired units (i.e., with a
design heat input capacity of less than 10 MMBtu/hr) are subject to
periodic tune-up work practices for CO and Hg in lieu of numeric
emission limits because the EPA found that it was technologically
[[Page 7489]]
and economically impracticable to apply measurement methodology to
these small sources, pursuant to CAA section 112(h).
Numerical emission limits, based on GACT, are established for PM as
a surrogate for urban metal HAP other than Hg for new large coal-fired
boilers. New and existing small coal-fired boilers are subject to
periodic tune-up management practices for PM as a surrogate for urban
metal HAP other than Hg, and for CO as a surrogate for urban organic
HAP other than POM, based on GACT.
New large biomass- and oil-fired boilers are subject to numerical
emission limits for PM as a surrogate for urban metal HAP, based on
GACT. Existing biomass and oil-fired boilers and new small biomass- and
oil-fired boilers are subject to periodic tune-up management practices
for PM as a surrogate for urban metal HAP, based on GACT. New and
existing biomass- and oil-fired boilers are subject to periodic tune-up
management practices for CO as a surrogate for urban organic HAP, based
on GACT. Certain other subcategories (seasonal boilers, limited-use
boilers, oil-fired boilers with heat input capacity of equal to or less
than 5 MMBtu/hr, and boilers with an oxygen trim system) are subject to
periodic tune-up work practice or management practice requirements
tailored to their schedule of operation and types of fuel.
The compliance date for existing sources is March 21, 2014. The
compliance date for new sources that began operations on or before May
20, 2011 is May 20, 2011. For new sources that start up after May 20,
2011, the compliance date is the date of startup. New sources are
defined as sources that began operation after June 4, 2010.
Costs and Benefits
This final action is intended to clarify definitions, references,
applicability and compliance issues, but not change the coverage of the
final rule. The final rule will affect an estimated 180,000 existing
area source boilers and the EPA projects that approximately an
additional 6,800 new boilers will be subject to the rule over the
initial 3-year period. The clarifications should make it easier for
owners and operators and for local and state authorities to understand
and implement the rule's requirements. As compared to the March 2011
final rule, this final rule will not affect the estimated emission
reductions, control costs or the benefits of the rule in substance.
This final rule does not impose any additional regulatory requirements
beyond those imposed by the previously promulgated boiler area source
rule and, in fact, will result in a decrease in regulatory requirements
for certain subcategories of boilers. A more detailed discussion of the
costs and benefits of the March 2011 final rule is provided at 76 FR
15579, March 21, 2011, and 76 FR 80542, December 23, 2011. Section VI
of this preamble provides a discussion of the impacts of this final
rule.
SUPPLEMENTARY INFORMATION:
Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.
7-PAH 7-polynuclear aromatic hydrocarbons
ACI activated carbon injection
ASTM American Society for Testing and Materials
Btu British thermal unit
CO carbon monoxide
CEMS continuous emission monitoring system
CDX Central Data Exchange
CAA Clean Air Act
CFR Code of Federal Regulations
COMS continuous opacity monitoring system
CPMS continuous parameter monitoring system
DOE Department of Energy
ERT Electronic Reporting Tool
ESP electrostatic precipitator
FR Federal Register
GACT generally available control technologies
HAP hazardous air pollutants
Hg mercury
HQ Headquarters
ISO International Standards Organization
lb pounds
MACT maximum achievable control technology
MMBtu million British thermal units
NAA No Action Assurance
NAICS North American Industry Classification System
NESHAP national emission standards for hazardous air pollutants
NSPS new source performance standard
NTTAA National Technology Transfer and Advancement Act
OMB Office of Management and Budget
PCBs polychlorinated biphenyls
PM particulate matter
POM polycyclic organic matter
ppm parts per million
PSD prevention of significant deterioration
RFA Regulatory Flexibility Act
RIN Regulatory Information Number
TBtu trillion British thermal units
TTN Technology Transfer Network
tpy tons per year
UMRA Unfunded Mandates Reform Act of 1995
UPL upper prediction limit
VCS Voluntary Consensus Standards
WWW Worldwide Web
Organization of This Document. The information presented in this
preamble is organized as follows:
I. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document?
C. Judicial Review
II. Background Information
III. Summary of Final Action on Reconsideration
A. Affected Sources
B. Source Category Exclusions
C. Emission Limits
D. Tune-Up Work Practice and Management Practice Standards
E. Energy Assessment Work Practice and Management Practice
Standards
F. GACT-Based Standards
G. Initial Compliance
H. Operating Limits
I. Continuous Compliance
J. Periods of Startup and Shutdown
K. Affirmative Defense Language
L. Notification, Recordkeeping and Reporting Requirements
M. Title V Permitting Requirements
N. Definition of Period of Gas Curtailment or Supply
Interruption
O. Miscellaneous Technical Corrections
P. Other Issues
IV. Summary of Significant Changes Since Proposed Action on
Reconsideration
A. Applicability
B. Tune-Up Requirements
C. Energy Assessment
D. Clarification of Oxygen Concentration Operating Limits
E. Definitions Regarding Averaging Times
F. Fuel Sampling Frequency
G. Performance Testing Frequency
H. Startup and Shutdown Definitions
I. Notifications
J. Miscellaneous Definitions
V. Other Actions the EPA Is Taking
VI. Impacts Associated With This Final Rule
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. Congressional Review Act
I. General Information
A. Does this action apply to me?
The regulated categories and entities potentially affected by this
action include:
[[Page 7490]]
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Industry category NAICS Code \a\ Examples of regulated entities
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Any area source facility using a 321 Wood product manufacturing.
boiler as defined in the final 11 Agriculture, greenhouses.
rule.. 311 Food manufacturing.
327 Nonmetallic mineral product manufacturing.
424 Wholesale trade, nondurable goods.
531 Real estate.
611 Educational services.
813 Religious, civic, professional, and similar organizations.
92 Public administration.
722 Food services and drinking places.
62 Health care and social assistance.
22111 Electric power generation.
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\a\ North American Industry Classification System.
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
final action. To determine whether your facility may be affected by
this action, you should examine the applicability criteria in 40 CFR
63.11193 of subpart JJJJJJ (National Emission Standards for Hazardous
Air Pollutants for Industrial, Commercial, and Institutional Boilers
Area Sources). If you have any questions regarding the applicability of
this final rule to a particular entity, consult either the air permit
authority for the entity or your EPA regional representative, as listed
in 40 CFR 63.13 of subpart A (General Provisions).
B. Where can I get a copy of this document?
In addition to being available in the docket, an electronic copy of
this action will also be available on the WWW through the TTN.
Following signature, a copy of the action will be posted on the TTN's
policy and guidance page for newly proposed or promulgated rules at the
following address: http://www.epa.gov/ttn/oarpg/. The TTN provides
information and technology exchange in various areas of air pollution
control.
C. Judicial Review
Under the CAA section 307(b)(1), judicial review of this final rule
is available only by filing a petition for review in the U.S. Court of
Appeals for the District of Columbia Circuit by April 2, 2013. Under
CAA section 307(d)(7)(B), only an objection to this final rule that was
raised with reasonable specificity during the period for public comment
can be raised during judicial review.
Under CAA section 307(b)(2), the requirements established by this
final rule may not be challenged separately in any civil or criminal
proceedings brought by EPA to enforce these requirements.
II. Background Information
Section 112(d) of the CAA requires the EPA to establish NESHAP for
both major and area sources of HAP that are listed for regulation under
CAA section 112(c). A major source is any stationary source that emits
or has the potential to emit 10 tpy or more of any single HAP or 25 tpy
or more of any combination of HAP. An area source is a stationary
source that is not a major source.
On March 21, 2011 (76 FR 15554), the EPA issued the NESHAP for
industrial, commercial and institutional area source boilers pursuant
to CAA sections 112(c)(3), 112(c)(6), and 112(k)(3)(B).
CAA section 112(k)(3)(B) directs the EPA to identify at least 30
HAP that, as a result of emissions from area sources, pose the greatest
threat to public health in the largest number of urban areas. The EPA
implemented this provision in 1999 in the Integrated Urban Air Toxics
Strategy, (64 FR 38715, July 19, 1999) (Strategy). Specifically, in the
Strategy, the EPA identified 30 HAP that pose the greatest potential
health threat in urban areas, and these HAP are referred to as the ``30
urban HAP.'' Section 112(c)(3) of the CAA requires the EPA to list
sufficient categories or subcategories of area sources to ensure that
area sources representing 90 percent of the emissions of the 30 urban
HAP are subject to regulation. Under CAA section 112(d)(5), the EPA may
elect to promulgate standards or requirements for area sources ``which
provide for the use of generally available control technologies
(``GACT'') or management practices by such sources to reduce emissions
of hazardous air pollutants.''
CAA section 112(c)(6) requires that the EPA list categories and
subcategories of sources assuring that sources accounting for not less
than 90 percent of the aggregate emissions of each of seven specified
HAP are subject to standards under CAA sections 112(d)(2) or (d)(4),
which require the application of the more stringent MACT. The seven HAP
specified in CAA section 112(c)(6) are as follows: Alkylated lead
compounds, POM, hexachlorobenzene, Hg, PCBs, 2,3,7,8-
tetrachlorodibenzofuran, and 2,3,7,8-tetrachlorodibenzo-p-dioxin.
As noted in the preamble to the final rule, (76 FR 15556, March 21,
2011), we listed area source industrial boilers and commercial/
institutional boilers combusting coal under CAA section 112(c)(6) based
on the source categories' contribution of Hg and POM, and under CAA
section 112(c)(3) for their contribution of arsenic, beryllium,
cadmium, lead, chromium, manganese, nickel, ethylene dioxide, and PCBs,
as well as Hg and POM. We promulgated final standards for coal-fired
area source boilers to reflect the application of MACT for Hg and POM,
and to reflect GACT for the urban HAP other than Hg and POM.
We listed industrial and commercial/institutional boilers
combusting oil or biomass under CAA section 112(c)(3) for their
contribution of Hg, arsenic, beryllium, cadmium, lead, chromium,
manganese, nickel, POM, ethylene dioxide, and PCBs. For boilers firing
oil or biomass, the final standards reflect GACT for all of the urban
HAP.
On March 21, 2011, we also published a notice to initiate the
reconsideration of certain aspects of the final rule for area source
industrial, commercial and institutional boilers (76 FR 15266). The
reconsideration notice identified several provisions of the final rule
where additional public comment was appropriate. The notice also
identified several issues of central relevance to the rulemaking where
reconsideration was appropriate under CAA section 307(d).
Following promulgation of the final rule, the EPA also received
petitions for reconsideration from the following organizations
(Petitioners): American
[[Page 7491]]
Sugar Cane League of the U.S.A., Alaska Oil and Gas Association,
American Coke and Coal Chemicals Institute, American Iron and Steel
Institute, American Petroleum Institute, Council of Industrial Boiler
Owners, Industry Coalition (American Forest and Paper Association
(AF&PA) et. al.), National Petrochemical and Refiners Association,
Sierra Club, and the State of Washington Department of Ecology.
Petitioners, pursuant to CAA section 307(d)(7)(B), requested that the
EPA reconsider numerous provisions in the rules. On December 23, 2011,
the EPA granted the petitions for reconsideration on certain issues,
and proposed certain revisions to the final rule in response to the
reconsideration petitions and to address the issues that the EPA
previously identified as warranting reconsideration. That proposal
solicited comment on several specific aspects of the rule, including:
Establishing separate requirements for seasonally operated
boilers.
Addressing temporary boilers.
Clarifying the initial compliance schedule for existing
boilers subject to tune-ups.
Defining periods of gas curtailment.
Providing an optional CO compliance mechanism using CEMS.
Averaging times for parameter monitoring.
Providing an affirmative defense for malfunction events.
Adjusting frequency of tune-up work practices for very
small units.
Selecting a 99 percent confidence interval for setting the
CO emission limit.
Establishing GACT-based limits for biomass and oil-fired
boilers.
Scope and duration of the energy assessment and deadline
for completing the assessment.
Revising GACT-based limits for PM at new oil-fired
boilers.
Exempting area sources from title V permitting
requirements.
In this action, the EPA is finalizing multiple changes to this
NESHAP after considering public comments on the items under
reconsideration.
III. Summary of Final Action on Reconsideration
As stated above, the December 23, 2011, proposed rule addressed
specific issues and provisions the EPA identified for reconsideration.
This summary reflects the agency's final action in regards to those
provisions identified for reconsideration and on other discrete matters
identified in response to comments or data received during the comment
period.
A. Affected Sources
This final rule amends 40 CFR 63.11194 to specify that an existing
dual-fuel fired boiler (i.e., commenced construction or reconstruction
on or before June 4, 2010) meeting the definition of gas-fired boiler,
as defined in 40 CFR 63.11237, that meets the applicability
requirements of subpart JJJJJJ after June 4, 2010 due to a fuel switch
from gaseous fuel to solid fossil fuel, biomass, or liquid fuel is
considered to be an existing source under this subpart as long as the
boiler was designed to accommodate the alternate fuel. A new or
reconstructed dual-fuel fired boiler (i.e., commenced construction or
reconstruction after June 4, 2010) meeting the definition of gas-fired
boiler, as defined in 40 CFR 63.11237, that meets the applicability
criteria of subpart JJJJJJ after June 4, 2010 due to a fuel switch from
gaseous fuel to solid fossil fuel, biomass, or liquid fuel is
considered to be a new source under this subpart.
B. Source Category Exclusions
This final rule amends the list of boilers that are not part of the
source categories subject to subpart JJJJJJ. We are revising this list
(as set forth in 40 CFR 63.11195) to clarify certain boiler types and
to include certain additional boilers that may be located at an
industrial, commercial or institutional area source facility. These
revisions of the source categories are described below.
1. Electric Boilers
The EPA is amending 40 CFR 63.11195 by adding electric boilers to
the list of boilers not subject to subpart JJJJJJ. Electric boilers are
defined in 40 CFR 63.11237 as follows:
Electric boiler means a boiler in which electric heating serves
as the source of heat. Electric boilers that burn gaseous or liquid
fuel during periods of electrical power curtailment or failure are
included in this definition.
2. Residential Boilers
The EPA is amending 40 CFR 63.11195 by adding residential boilers
to the list of boilers not subject to subpart JJJJJJ. We are clarifying
that a residential boiler may be part of a residential combined heat
and power system and that a boiler serving a single unit residence
dwelling that has since been converted or subdivided into condominiums
or apartments may also be considered a residential boiler. Residential
boilers are defined in 40 CFR 63.11237 as follows:
Residential boiler means a boiler used to provide heat and/or
hot water and/or as part of a residential combined heat and power
system. This definition includes boilers located at an institutional
facility (e.g., university campus, military base, church grounds) or
commercial/industrial facility (e.g., farm) used primarily to
provide heat and/or hot water for:
(1) A dwelling containing four or fewer families, or
(2) A single unit residence dwelling that has since been
converted or subdivided into condominiums or apartments.
3. Temporary Boilers
The EPA is amending 40 CFR 63.11195 by adding temporary boilers to
the list of boilers not subject to subpart JJJJJJ. Similar to
residential boilers, we did not intend to regulate temporary boilers
under the area source standards because they are not part of either the
industrial boiler source category or the commercial/institutional
boiler source category. We note that neither the CAA section 112(c)(6)
inventory nor the CAA section 112(c)(3) inventory included temporary
boilers. In this final action, the EPA is simply clarifying the scope
of categories regulated by subpart JJJJJJ. By their nature of being
temporary, these boilers are operating in place of another non-
temporary boiler while that boiler is being constructed, replaced or
repaired, in which case we would have counted the non-temporary boiler
as one being regulated. Additionally, the final major source rule for
boilers excludes temporary boilers.
The definition of ``temporary boiler'' specifies that a boiler is
not a temporary boiler if it remains at a location within the facility
and performs the same or similar function for more than 12 consecutive
months unless the regulatory agency approves an extension. The
definition of ``temporary boiler'' also specifies that any temporary
boiler that replaces a temporary boiler at a location within the
facility and performs the same or similar function will be included in
calculating the consecutive time period unless there is a gap in
operation of 12 months or more. Temporary boilers are defined in 40 CFR
63.11237 as follows:
Temporary boiler means any gaseous or liquid fuel boiler that is
designed to, and is capable of, being carried or moved from one
location to another by means of, for example, wheels, skids,
carrying handles, dollies, trailers, or platforms. A boiler is not a
temporary boiler if any one of the following conditions exists:
(1) The equipment is attached to a foundation.
(2) The boiler or a replacement remains at a location within the
facility and performs the same or similar function for more than 12
consecutive months, unless the regulatory agency approves an
extension. An extension may be granted by the regulatory agency
[[Page 7492]]
upon petition by the owner or operator of a unit specifying the
basis for such a request. Any temporary boiler that replaces a
temporary boiler at a location within the facility and performs the
same or similar function will be included in calculating the
consecutive time period unless there is a gap in operation of 12
months or more.
(3) The equipment is located at a seasonal facility and operates
during the full annual operating period of the seasonal facility,
remains at the facility for at least 2 years, and operates at that
facility for at least 3 months each year.
(4) The equipment is moved from one location to another within
the facility but continues to perform the same or similar function
and serve the same electricity, steam, and/or hot water system in an
attempt to circumvent the residence time requirements of this
definition.
4. Boilers With Section 3005 Permits
The EPA is clarifying the language in 40 CFR 63.11195(c) to provide
an exclusion stating ``unless such units do not combust hazardous waste
and combust comparable fuels'' such that it reads: ``A boiler required
to have a permit under section 3005 of the Solid Waste Disposal Act or
covered by subpart EEE of this part (e.g., hazardous waste boilers),
unless such units do not combust hazardous waste and combust comparable
fuels.''
5. Boilers Used as Control Devices
The EPA is amending the language in 40 CFR 63.11195(g) to clarify
that any boiler that is used as a control device to comply with a
subpart under part 60, 61, or 65 of chapter 40 is not subject to
subpart JJJJJJ provided that at least 50 percent of the heat input to
the boiler is provided by the gas stream that is regulated under
another subpart.
C. Emission Limits
1. Hg Emission Limit for Coal-Fired Boilers
The EPA is amending the Hg emission limit for large coal-fired
boilers to 0.000022 lb per MMBtu based on a revised analysis. The
revised analysis excludes data for a utility boiler that were
erroneously used as the basis for the Hg emission limit included in the
March 2011 final rule. Further discussion of this revision to the Hg
emission limit is located in the December 23, 2011, proposal (76 FR
80541).
A memorandum ``Beyond-the-Floor Analysis for Mercury and Carbon
Monoxide'' located in the docket for the rulemaking describes our
beyond-the-floor analysis for Hg and CO emissions from new and existing
area source coal-fired boilers with heat input capacity of 10 MMBtu/hr
or greater. In the beyond-the-floor option for Hg emissions, new and
existing coal-fired boilers would be required to comply with a Hg
emission limit more stringent than the MACT floor-based emission limit
of 2.2 X 10-\5\ lb of Hg per MMBtu. To comply with a limit
more stringent than the fabric filter-based MACT floor limit, it is
expected that an affected boiler would need to employ fabric filter
control along with ACI. In summary, we determined that the beyond-the-
floor option of installing ACI for Hg control from area source coal-
fired boilers is not economically feasible.
As discussed in the preamble to the June 2010 proposed rule (75 FR
31896) and the preamble to the March 2011 final rule (76 FR 15554), we
also considered whether fuel switching was an appropriate control
technology for purposes of determining either the MACT floor level or
beyond-the-floor level of control. We determined that fuel switching
was not an appropriate floor or beyond-the-floor control. As also
discussed in the June 2010 and March 2011 preambles, we determined that
an energy assessment requirement was an appropriate beyond-the-floor
option for existing large boilers. These previous analyses continue to
be applicable for mercury.
2. Using the UPL for Setting the CO Emission Limit
The EPA is amending the CO emission limit for coal-fired boilers to
reflect a revised analysis that uses the 99 percent confidence level in
determining the UPL. Based on the results of the revised analysis, we
are amending the CO emission limit for new and existing coal-fired
boilers from 400 ppm by volume on a dry basis, corrected to 3 percent
oxygen, to 420 ppm by volume on a dry basis, corrected to 3 percent
oxygen.
As discussed in the ``Beyond-the-Floor Analysis for Mercury and
Carbon Monoxide'' memorandum, to comply with a limit more stringent
than the MACT floor based CO limit, it is expected that new and
existing area source coal-fired boilers with heat input capacity of 10
MMBtu/hr or greater may need to install an oxidation catalyst. As fully
explained in the memorandum, we determined that the beyond-the-floor
option of installing an oxidation catalyst for CO control was
technically infeasible. Other methods of reducing CO emissions, such as
upgrading new burners and overfire air systems, were also considered
and determined to be technically infeasible options. As explained
earlier in this preamble, we determined that fuel switching was not an
appropriate floor or beyond-the-floor control and that an energy
assessment requirement was an appropriate beyond-the-floor option for
existing large boilers. These previous analyses continue to be
applicable for CO.
3. Compliance Alternative for PM for Certain Oil-Fired Boilers
The EPA is amending the applicability of PM emission limit
requirements for certain new or reconstructed oil-fired boilers. We are
amending 40 CFR 63.11210 to specify that new or reconstructed oil-fired
boilers satisfy GACT for PM when they combust only oil that contains no
more than 0.50 weight percent sulfur or a mixture of 0.50 weight
percent sulfur oil with other fuels not subject to a PM emission limit
under this subpart and do not use a post-combustion technology (except
a wet scrubber) to reduce PM or sulfur dioxide emissions.
D. Tune-Up Work Practice and Management Practice Standards
1. Requirements for Seasonally Operated Boilers
The EPA is establishing separate requirements for a subcategory of
boilers that are seasonally operated. For seasonally operated boilers,
we are amending 40 CFR 63.11223 to specify that these boilers are
required to complete a tune-up every 5 years, instead of on a biennial
basis as is required for most non-seasonal boilers. Specifically,
existing seasonal boilers are required to complete the initial tune-up
by March 21, 2014, and a subsequent tune-up every 5 years after the
initial tune-up. New and reconstructed seasonal boilers are not
required to complete an initial tune-up, but are required to complete a
tune-up every 5 years after the initial startup of the new or
reconstructed boiler.\1\ A combined total of 15 days of periodic
testing of the seasonal boiler during the 7-month shutdown is allowed.
The definition of ``seasonal boiler'' clarifies that it only applies to
biomass- or oil-fired boilers. Seasonally operated boilers are defined
in 40 CFR 63.11237 as follows:
---------------------------------------------------------------------------
\1\ Generally, boilers are initially installed optimized for
efficiency, i.e., ``in tune.'' Periodic tune-ups restore a boiler to
its efficient state, given its age and other parameters. We do not
require a tune-up upon startup because boilers normally would
already be efficient at that time. Emission reductions are projected
to occur by maintaining efficient combustion through periodic tune-
ups.
Seasonal boiler means a boiler that undergoes a shutdown for a
period of at least 7 consecutive months (or 210 consecutive days)
each 12-month period due to seasonal conditions, except for periodic
testing. Periodic testing shall not exceed a combined total of 15
days during the 7-month shutdown. This definition only applies to
[[Page 7493]]
boilers that would otherwise be included in the biomass subcategory
or the oil subcategory.
2. Requirements for Small Oil-Fired Units
The EPA is establishing separate requirements for a subcategory of
oil-fired boilers with a heat input capacity of equal to or less than 5
MMBtu/hr. We are amending 40 CFR 63.11223 to specify that this
subcategory of small oil-fired boilers are required to complete a tune-
up every 5 years, instead of on a biennial basis as is required for
most larger oil-fired boilers. Specifically, existing oil-fired boilers
with a heat input capacity of equal to or less than 5 MMBtu/hr are
required to complete the initial tune-up by March 21, 2014, and a
subsequent tune-up every 5 years after the initial tune-up. New and
reconstructed oil-fired boilers with a heat input capacity of equal to
or less than 5 MMBtu/hr are not required to complete an initial tune-
up, but are required to complete a tune-up every 5 years after the
initial startup of the new or reconstructed boiler.
3. Requirements for Boilers With Oxygen Trim Systems
The EPA is establishing separate requirements for boilers with
oxygen trim systems that maintain an optimum air-to-fuel ratio that
would otherwise be subject to a biennial tune-up. We are amending 40
CFR 63.11223 to specify that this subcategory of boilers is required to
complete a tune-up every 5 years. Specifically, existing boilers with
oxygen trim systems are required to complete the initial tune-up by
March 21, 2014, and a subsequent tune-up every 5 years after the
initial tune-up. New and reconstructed boilers with oxygen trim systems
are not required to complete an initial tune-up, but are required to
complete a tune-up every 5 years after the initial startup of the new
or reconstructed boiler.
4. Requirements for Limited-Use Boilers
The EPA is establishing separate requirements for a subcategory of
boilers that operate on a limited basis. The limited-use subcategory
includes any boiler that burns any amount of solid or liquid fuels and
has a federally enforceable average annual capacity factor of no more
than 10 percent. For limited-use boilers, we are amending 40 CFR
63.11223 of the final rule to specify that these boilers are required
to complete a tune-up every 5 years. Specifically, existing limited-use
boilers are required to complete the initial tune-up by March 21, 2014,
and a subsequent tune-up every 5 years after the initial tune-up. New
and reconstructed limited-use boilers are not required to complete an
initial tune-up, but are required to complete a tune-up every 5 years
after the initial startup of the new or reconstructed boiler. Limited-
use boilers are not subject to the emission limits in Table 1 to the
subpart, the energy assessment requirements in Table 2 to the subpart,
or the operating limits in Table 4 to the subpart.
E. Energy Assessment Work Practice and Management Practice Standards
1. Scope
The EPA is amending the definition of ``energy assessment'' to
clarify that the scope of the energy assessment does not encompass
energy use systems located off-site or energy use systems using
electricity purchased from an off-site source. The energy assessment is
limited to only those energy use systems, located on-site, associated
with the affected boilers. We are also clarifying that the scope of the
assessment is based on energy use by discrete segments of a facility
(e.g., production area or building) and not by a total aggregation of
all individual energy using segments of a facility.
The definition of ``boiler system'' is being revised in this final
rule to clarify that it means the boiler and associated components
directly connected to and serving the energy use systems. We are
amending the definition of ``energy use system'' to clarify that energy
use systems are only those systems using energy clearly produced by
affected boilers.
We are clarifying that energy assessor approval and qualification
requirements are waived in instances where an energy assessment
completed on or after January 1, 2008 meets or is amended to meet the
energy assessment requirements in this final rule by March 21, 2014.
Finally, we are specifying that a source that is operating under an
energy management program established through energy management systems
compatible with ISO 50001, that includes the affected boilers, by March
21, 2014, satisfies the energy assessment requirement. We consider
these energy management programs to be equivalent to the one-time
energy assessment because facilities having these programs operate
under a set of practices and procedures designed to manage energy use
on an ongoing basis. These programs contain energy performance
measurements and tracking plans with periodic reviews.
2. Compliance Date
As specified in 40 CFR 63.11196(a)(3), existing boilers that are
subject to the energy assessment requirement must achieve compliance
with the energy assessment requirement no later than March 21, 2014.
Thus, in order to meet the requirements of the rule, energy assessments
must, therefore, be completed by the compliance date (March 21, 2014)
for existing sources.
3. Maximum Duration Requirements
The EPA is amending the definition of ``energy assessment'' for
facilities with affected boilers with less than 0.3 TBtu/yr heat input
capacity and for facilities with affected boilers with 0.3 to 1 TBtu/yr
heat input capacity to change the maximum time to conduct the energy
assessment from one day to 8 on-site technical hours and from three
days to 24 on-site technical hours, respectively, and to allow sources
to perform longer assessments at their discretion. We are also amending
the definition of ``energy assessment'' for facilities with affected
boilers with greater than 1 TBtu/yr heat input capacity to specify that
the maximum time to conduct the assessment is up to 24 on-site
technical hours for the first TBtu/yr plus 8 on-site technical hours
for every additional 1.0 TBtu/yr not to exceed 160 on-site technical
hours, but may be longer at the discretion of the owner or operator.
F. GACT-Based Standards
1. Establishing GACT-Based Emission Limits for Biomass- and Oil-Fired
Boilers
The EPA is not amending the GACT-based standards, as specified in
the March 21, 2011, final rule, for biomass- and oil-fired boilers.
Specifically, the final standards for biomass- and oil-fired area
source boilers are based on GACT instead of MACT as were the proposed
standards for all pollutants except POM. Our rationale for the changes
between proposal and promulgation for the biomass- and oil-fired
boilers, including not requiring MACT for POM, can be found in the
preamble to the promulgated area source standards (76 FR 15565-15567
and 15574-15575, March 21, 2011). The final standards for area source
biomass- and oil-fired boilers require these boilers to meet the
following standards:
New boilers with heat input capacity greater than 10 MMBtu/hr that
are biomass-fired or oil-fired must meet GACT-based numerical emission
limits for PM.
New boilers with heat input capacity greater than 10 MMBtu/hr that
are biomass-fired or oil-fired must comply
[[Page 7494]]
with work practice standards to minimize the boiler's startup and
shutdown periods following the manufacturer's recommendations, or the
manufacturer's recommendations for a unit of similar design.
Existing boilers with heat input capacity greater than 10 MMBtu/hr
that are biomass-fired or oil-fired must have a one-time energy
assessment performed by a qualified energy assessor, an energy
assessment completed on or after January 1, 2008 that meets or is
amended to meet the energy assessment requirements in this final rule
by March 21, 2014, or an energy management program established through
energy management systems compatible with ISO 50001, that includes the
affected boilers, by March 21, 2014, under which the owner or operator
currently operates.
All new and existing units, regardless of size, that are biomass-
fired or oil-fired must have a GACT-based periodic tune-up.
2. Setting GACT-Based PM Standards for New Oil-Fired Boilers
The EPA is not making any changes to the PM limit for new oil-fired
boilers. New oil-fired boilers with heat input capacity greater than 10
MMBtu/hr must meet a GACT-based numerical emission limit for PM (0.03
lb per MMBtu of heat input). New oil-fired units, regardless of size,
must have a GACT-based periodic tune-up. Our rationale for finalizing
GACT-based PM emissions limits can be found in the preamble to the
promulgated area source standards (76 FR 15574, March 21, 2011).
G. Initial Compliance
1. Dates
Some commenters have argued that the 3-year compliance deadline of
March 21, 2014, for existing sources to meet the standards does not
provide sufficient time for sources to meet the standards in view of
the large number of sources subject to the rule and that these sources
will be competing for the needed resources and materials from
engineering consultants, permitting authorities, equipment vendors,
construction contractors, financial institutions, and other critical
suppliers.
As an initial matter, we note that many sources subject to the
standards should be able to meet the standards within 3 years (i.e., by
March 21, 2014), even those that need to install pollution control
technologies to do so. In addition, many sources subject to the
standards are existing biomass- or oil-fired boilers or small coal-
fired boilers (less than 10 MMBtu/hr) and will not need to install
controls in order to demonstrate compliance, as these sources are
subject only to work practices or management practices.
At the same time, the CAA allows title V permitting authorities to
grant sources, on a case-by-case basis, extensions to the compliance
time of up to 1 year if such time is needed for the installation of
controls. See CAA section 112(i)(3)(B)). Permitting authorities are
already familiar with, and in many cases have experience with, applying
the 1-year extension authority under section 112(i)(3)(B) since the
provision applies to all NESHAP. See 40 CFR 63.6(i)(4)(A). We believe
that should the range of circumstances that commenters have cited as
impeding sources' ability to install controls within 3 years
materialize, then permitting authorities can take those circumstances
into consideration when evaluating an existing source's request for a
1-year extension, and where such applications prove to be well-founded,
permitting authorities can make the 1-year extension available to
applicants.
In making a determination as to whether an extension is
appropriate, we believe it is reasonable for permitting authorities to
consider the large number of pollution control retrofit projects being
undertaken for purposes of complying either with the standards in this
rule or with those of other rules such as the Major Source Boilers
Standards and the Mercury and Air Toxics Standards for the power sector
that may be competing for similar resources.
Further, commenters have pointed out that in some cases operators
of existing sources that are subject to these standards and that
generate energy may opt to meet the standards by terminating operations
at these sources and building new sources to replace the energy
generation at the shut-down sources. While the ultimate discretion to
provide a 1-year extension lies with the permitting authority, the EPA
believes that it may be reasonable for permitting authorities to allow
the fourth year extension for the installation of replacement sources
of energy generation at the site of a facility applying for an
extension for that purpose. Specifically, the EPA believes where an
applicant demonstrates that it is building replacement sources of
energy generation for purposes of meeting the requirements of these
standards, such a replacement project could be deemed to constitute the
``installation of controls'' under section 112(i)(3)(B).
In sum, the EPA believes that although most, if not all, units will
be able to fully comply with the standards within 3 years, the fourth
year that permitting authorities are allowed to grant for installation
of controls is an important flexibility that will address situations
where an extra year is necessary.
2. Demonstrating Initial Compliance
The EPA is amending 40 CFR 63.11210 to clarify the dates by which
new and reconstructed boilers need to demonstrate initial compliance.
We are amending 40 CFR 63.11210(d) to clarify that only boilers that
are subject to emission limits for PM, Hg or CO in Table 1 to subpart
JJJJJJ have a 180-day period after the applicable compliance date to
demonstrate initial compliance.
We are adding a new paragraph (i) to 40 CFR 63.11210 to clarify the
initial compliance requirements for boilers located at existing major
sources of HAP that become area sources on a timely basis. Any such
existing boiler at the existing source must demonstrate compliance with
subpart JJJJJJ within 180 days of the later of March 21, 2014 or upon
the existing major source commencing operation as an area source. Any
new or reconstructed boiler at the existing source must demonstrate
compliance with subpart JJJJJJ within 180 days of the later of March
21, 2011 or startup. Notification of such changes must be submitted
according to 40 CFR 63.11225(g).
We are adding a new paragraph (j) to 40 CFR 63.11210 that specifies
initial compliance demonstration requirements for existing affected
boilers that have not operated between the effective date of the rule
and the source's compliance date. Owners and operators of boilers
subject to emission limits must complete the initial compliance
demonstration no later than 180 days after the re-start of the affected
boiler, sources subject to tune-up requirements must complete the
initial performance tune-up no later than 30 days after the re-start of
the affected boiler, and sources subject to the one-time energy
assessment must complete the assessment no later than the compliance
date specified in 40 CFR 63.11196.
3. Schedule for Existing Boilers Subject to Tune-Up Requirements
The EPA is amending 40 CFR 63.11196 to specify that all existing
boilers subject to the tune-up requirement have 3 years (by March 21,
2014) in which to demonstrate initial compliance, instead of 1 year as
specified in the 2011 final rule (76 FR 15554, March 21, 2011) or 2
years as specified in the proposed reconsideration of final rule action
(76
[[Page 7495]]
FR 80532, December 23, 2011). In the December 23, 2011, proposal, we
specifically requested comment on whether the initial compliance period
for the tune-up requirement should be extended to March 21, 2014.
4. Conducting Initial Tune-Ups at New and Reconstructed Sources
The EPA is removing the requirement for an initial tune-up for new
and reconstructed boilers. Thus, new and reconstructed units are
required to complete the applicable biennial or 5-year tune-up no later
than 25 months or 61 months, respectively, after the initial startup of
the new or reconstructed boiler.
5. Fuel Requirements
The EPA is amending 40 CFR 63.11223(a) to specify that boiler tune-
ups must be conducted while burning the type of fuel that provided the
majority of the heat input to the boiler over the 12 months prior to
the tune-up.
H. Operating Limits
1. Operating Limits for Oxygen Concentration
The EPA is clarifying that the oxygen concentration must be at or
above the minimum established during a performance stack test. These
limits have also been clarified to be applicable when the unit is
firing the fuel or fuel mixture utilized during the CO performance
test.
2. Maximum Operating Load
The EPA is including provisions for establishing a unit-specific
limit for maximum operating load that applies to any boiler subject to
an emission limit for which compliance is demonstrated by a performance
stack test. Operating load data includes fuel feed rate data or steam
generation rate data.
3. Establishing Operating Limits for Wet Scrubbers
The EPA is amending the operating limit provisions in 40 CFR
63.11211(b)(2) for an ESP operated with a wet scrubber to remove the
statement that the operating limits for ESP do not apply to dry ESP
systems operated without a wet scrubber.
I. Continuous Compliance
1. CO Emission Limit
The March 2011 final rule requires sources subject to a CO emission
limit to demonstrate compliance by measuring CO emissions while also
monitoring the oxygen content of the exhaust. We are amending the
monitoring requirements in 40 CFR 63.11224(a) to allow sources subject
to a CO emission limit the option to install, operate, and maintain CO
and oxygen CEMS. The CEMS must be installed, operated and maintained
according to Performance Specifications 3 and 4, 4A, or 4B at 40 CFR
part 60, appendix B, and according to the site-specific monitoring plan
that each facility is required to develop. The CEMS will also be
required to complete a performance evaluation, also according to
Performance Specifications 3 and 4, 4A, or 4B.
Sources have the option to demonstrate continuous compliance by
monitoring both CO and oxygen using CEMS to demonstrate compliance with
the CO emission limit, corrected to 3 percent oxygen, or monitoring and
complying with an oxygen content operating limit that is established
during the performance stack test. Sources that use CO and oxygen CEMS
are not required to perform initial CO performance testing nor are they
subject to oxygen content operating limit requirements. Sources that
choose to demonstrate continuous compliance by monitoring and complying
with an oxygen content operating limit must install, operate, and
maintain an oxygen analyzer system at or above the minimum percent
oxygen by volume that is established as the operating limit for oxygen
when firing the fuel or fuel mixture utilized during the most recent CO
performance stack test. We have removed the requirement that the oxygen
monitor be located at the outlet of the boiler, so that it can be
located either within the combustion zone or at the outlet as a flue
gas oxygen monitor.
We are amending the oxygen monitoring requirements to allow for the
use of oxygen trim systems and have included oxygen trim systems in the
definition of ``oxygen analyzer system.'' We have clarified that
operation of oxygen trim systems to meet the oxygen monitoring
requirements shall not be done in a manner that compromises furnace
safety. The definitions of ``oxygen analyzer system'' and ``oxygen trim
system'' in 40 CFR 63.11237 read as follows:
Oxygen analyzer system means all equipment required to
determine the oxygen content of a gas stream and used to monitor oxygen
in the boiler flue gas, boiler firebox, or other appropriate
intermediate location. This definition includes oxygen trim systems.
Oxygen trim system means a system of monitors that is used
to maintain excess air at the desired level in a combustion device. A
typical system consists of a flue gas oxygen and/or carbon monoxide
monitor that automatically provides a feedback signal to the combustion
air controller.
2. Tune-Up Standards
The EPA is amending the requirements for demonstrating continuous
compliance with the work practice and management practice tune-up
standards in 40 CFR 63.11223 to clarify that CO measurements that are
required before and after tune-up adjustments may be taken using a
portable CO analyzer. We are clarifying that the requirements to
inspect the burner and the system controlling the air-to-fuel ratio may
be delayed until the next scheduled shutdown. We are also clarifying
that units that produce electricity for sale may delay these
inspections until the first outage, not to exceed 36 months from the
previous inspection. In addition, we are clarifying that optimization
of CO emissions should be consistent with any NOX
requirements to which the unit is subject. Finally, we are specifying
for units that are not operating on the required date for a tune-up,
the tune-up must be conducted within 30 days of startup.
3. Performance Testing Frequency
The EPA is amending 40 CFR 63.11220 to specify in paragraph (b)
that the owner or operator of an affected boiler does not need to
conduct further PM emissions testing if, when demonstrating initial
compliance with the PM emission limit, the performance test results
show that the PM emissions are equal to or less than half of the PM
emission limit. The owner or operator must continue to comply with all
applicable operating limits and monitoring requirements. If the initial
performance test results show that the PM emissions are greater than
half of the PM emission limit, the owner or operator must conduct
subsequent performance tests as specified in 40 CFR 63.11220(a).
We are clarifying in 40 CFR 63.11220(d) that existing affected
boilers that have not operated since the previous compliance
demonstration must complete their subsequent compliance demonstration
no later than 180 days after the re-start of the affected boiler.
4. Fuel Analysis
The EPA is amending 40 CFR 63.11220 to specify in paragraph (c)
that the owner or operator of an affected coal-fired boiler does not
need to conduct further fuel analysis sampling if, when demonstrating
initial compliance with the Hg emission limit, the Hg constituents in
the fuel or fuel
[[Page 7496]]
mixture are measured to be equal to or less than half of the Hg
emission limit. The owner or operator must continue to comply with all
applicable operating limits and monitoring requirements.
When demonstrating initial compliance with the Hg emission limit,
if the Hg constituents in the fuel or fuel mixture are greater than
half of the Hg emission limit, the owner or operator must conduct
quarterly sampling.
5. Averaging Times
The EPA is amending the averaging time for parameter monitoring and
compliance with operating limits to a 30-day rolling average.
The EPA is revising the definitions of ``30-day rolling average''
and ``daily block average'' to exclude periods of startup and shutdown
and periods when the unit is not operating in the calculation of the
arithmetic mean.
6. Monitoring Data
The EPA is clarifying in 40 CFR 63.11221 the monitoring data
collection requirements.
J. Periods of Startup and Shutdown
1. Definitions
The EPA is revising the definitions of ``startup'' and ``shutdown''
such that they are tailored for industrial boilers and are consistent
with the definitions of ``startup'' and ``shutdown'' in the 40 CFR part
63, subpart A General Provisions. The revised definitions reflect the
fact that industrial boilers function to provide steam or, in the case
of cogeneration units, electricity. We are defining startup as the
period between either the first-ever firing of fuel in the boiler or
the firing of fuel in the boiler after a shutdown and when the boiler
first supplies steam or heat. We are defining shutdown as the period
between either when no more steam or heat is supplied by the boiler or
no fuel is being fired in the boiler and when there is no steam and no
heat being supplied and no fuel being fired in the boiler.
2. Compliance With Operating Limits
The EPA has clarified that operating limits must be met at all
times except during periods of startup and shutdown.
3. Minimization of Startup and Shutdown Periods
The EPA is amending 40 CFR 63.11223(g) to include biomass- and oil-
fired boilers in the requirement to minimize the time spent in startup
and shutdown periods. Specifically, the requirement is to minimize the
boiler's startup and shutdown periods and conduct startups and
shutdowns according to the manufacturer's recommended procedures. If
manufacturer's recommended procedures are not available, recommended
procedures for a unit of similar design for which manufacturer's
recommended procedures are available must be followed.
K. Affirmative Defense Language
In this final rule, the EPA is updating the affirmative defense
provisions for malfunctions that were included in the March 21, 2011,
final rule. We have made certain changes to 40 CFR 63.11226 to clarify
the circumstances under which a source may assert an affirmative
defense. The changes clarify that a source may assert an affirmative
defense to a claim for civil penalties for violations of standards that
are caused by malfunctions. A source can avail itself of the
affirmative defense when there has been a violation of the emission
standards due to an event that meets the definition of malfunction
under 40 CFR 63.2 and qualifies for assertion of an affirmative defense
under 40 CFR 63.11226. In the March 2011 final rule, we used terms such
as ``exceedance'' or ``excess emissions'' in 40 CFR 63.11226, which
created unnecessary confusion as to when the affirmative defense could
be used. In this final rule, we have eliminated those terms and used
the word ``violation'' to make clear that the affirmative defense to
civil penalties is available only where an event that causes a
violation of the emissions standard meets the criteria for the
assertion of an affirmative defense under 40 CFR 63.11226.
This final rule requires that to establish the affirmative defense
the owner must prove by a preponderance of evidence that repairs were
made as expeditiously as possible when a violation occurs. We have re-
evaluated the language concerning the use of off-shift and overtime
labor, to the extent practicable, to make the repairs and believe that
the language is not necessary. Thus, the language has been eliminated
from this final rule.
We have also eliminated the 2-day notification requirement that was
included in 40 CFR 63.11226(b) of the March 2011 final rule because we
expect to receive sufficient notification of malfunction events that
result in violations in other required compliance reports as specified
under 40 CFR 63.11225. In addition, we have revised the 45-day
affirmative defense reporting requirement that was included in 40 CFR
63.11226(b) of the March 2011 final rule. This final rule requires
sources to include the report in the first compliance, deviation or
excess emission report due after the initial occurrence of the
violation, unless the compliance, deviation or excess emission report
is due less than 45 days after the violation. In that case, the
affirmative defense report may be included in the second compliance,
deviation or excess emission report due after the initial occurrence of
the violation. Because the affirmative defense report is now included
in a subsequent compliance, deviation or excess emission report, there
is no longer a need for the 30-day extension for submitting a stand-
alone affirmative defense report. Consequently, we are not including
that provision in this final rule.
L. Notification, Recordkeeping and Reporting Requirements
The EPA is amending 40 CFR 63.11225(a)(2) to specify that existing
affected boilers have until January 20, 2014 to submit their Initial
Notification.
The EPA is amending 40 CFR 63.11225(c)(2) to specify that records
of fuel use and type are required only for boilers that are subject to
numerical emission limits. We are also amending 40 CFR 63.11223(b) to
clarify that the type and amount of fuel needs to be included in
reports only if the boiler was physically and legally capable of using
more than one type of fuel during that time period and that the report
should include concentrations of CO and oxygen, measured at high fire
or typical operating load, before and after the tune-up of the boiler.
Finally, we are specifying that for units sharing a fuel meter, the
fuel use by each boiler may be estimated.
The EPA is amending 40 CFR 63.11225(b) to clarify the requirements
for submitting a biennial or 5-year report for units that are only
subject to tune-up requirements and to specify the information that
must be included in the annual, biennial, or 5-year compliance report.
We are amending 40 CFR 63.11225(c)(2) to specify, as applicable,
that a copy of the energy assessment, records documenting the days of
operation for each boiler that meets the definition of a seasonal
boiler, and a copy of the federally enforceable permit for each boiler
that meets the definition of a limited-use boiler must be maintained.
We are revising 40 CFR 63.11225(d) to remove the requirement that
the most recent 2 years of records be maintained on site and are adding
language that allows for computer access or other means of immediate
access of records stored in a centralized location.
[[Page 7497]]
We are adding a new paragraph 40 CFR 63.11225(g) to require that
boilers that switch fuels, make a physical change, or take a permit
limit that results in the applicability of a different subcategory
within subpart JJJJJJ, a switch out of subpart JJJJJJ, or the
applicability of subpart JJJJJJ must provide notification within 30
days of the fuel switch, physical change, or permit limit. 40 CFR
63.11225(g) also specifies what information the notification must
include.
M. Title V Permitting Requirements
For the reasons stated in our March 21, 2011, final rule (76 FR
15554) as well as our reconsideration proposal (76 FR 80532, December
23, 2011), the EPA is not making any changes to the title V exemption
for area sources. Thus, no area sources subject to subpart JJJJJJ are
required to obtain a title V permit as a result of being subject to
subpart JJJJJJ.
Facilities that are synthetic area sources for HAP under subpart
JJJJJJ may already be covered by a title V permit or may be required to
obtain a title V permit in the future for a reason other than subpart
JJJJJJ. For example, area source boilers could be major sources of non-
HAP pollutants or could be located at sources that are subject to title
V. Thus, the title V exemption in subpart JJJJJJ does not affect
whether or not these area sources under subpart JJJJJJ are otherwise
required to obtain a permit under part 70 or part 71. See 40 CFR
70.3(a) and (b) or 71.3(a) and (b).
N. Definition of Period of Gas Curtailment or Supply Interruption
We are amending the definition of ``period of natural gas
curtailment or supply interruption'' in 40 CFR 63.11237 to clarify that
a curtailment does not include normal market fluctuations in the price
of gas that are not associated with periods of supplier delivery
restrictions. We are also amending the definition to indicate that
periods of supply interruption that are beyond control of the facility
can also include on-site natural gas system emergencies and equipment
failures, and that legitimate periods of supply interruption are not
limited to off-site circumstances. We are revising the term and the
definition so that it includes the curtailment of any gaseous fuel, and
is not limited to just natural gas. Finally, we are clarifying that the
supply of gaseous fuel is to an ``affected boiler'' rather than
``affected facility'' and that the supply of gaseous fuel is
``restricted or halted'' for reasons beyond the control of the
facility. The definition is amended to read as follows:
Period of gas curtailment or supply interruption means a period
of time during which the supply of gaseous fuel to an affected
boiler is restricted or halted for reasons beyond the control of the
facility. The act of entering into a contractual agreement with a
supplier of natural gas established for curtailment purposes does
not constitute a reason that is under the control of a facility for
the purposes of this definition. An increase in the cost or unit
price of natural gas due to normal market fluctuations not during
periods of supplier delivery restriction does not constitute a
period of natural gas curtailment or supply interruption. On-site
gaseous fuel system emergencies or equipment failures qualify as
periods of supply interruption when the emergency or failure is
beyond the control of the facility.
O. Miscellaneous Technical Corrections
In addition to the above summary of the EPA's final action
regarding provisions identified for reconsideration and on other
discrete matters identified in response to comments or data received
during the comment period, other definitional and regulatory text
revisions are being made. These clarifications will help affected
sources determine their applicability and better understand the rule
requirements. In some instances, definitions and regulatory text have
been revised or added to correspond with other related rules,
especially the emission standards for industrial, commercial, and
institutional boilers at major sources of HAP (40 CFR part 63, subpart
DDDDD). Section IV of this preamble includes additional details
regarding these miscellaneous technical corrections.
P. Other Issues
40 CFR 63.11196(a)(1) of the March 21, 2011, final rule (76 FR
15554) requires that owners and operators of existing affected boilers
subject to the tune-up requirement complete the initial boiler tune-up
by March 21, 2012. In addition, 40 CFR 63.11225(a)(4) requires that
owners and operators of existing affected boilers subject to the tune-
up requirement submit their Notification of Compliance Status no later
than 120 days after the applicable compliance date specified in 40 CFR
63.11196. That means that those owners and operators were required to
submit their Notification of Compliance Status by July 19, 2012. The
Notification must include, among other information, a certification
that states ``This facility complies with the requirements in Sec.
63.11214 to conduct an initial tune-up of the boiler.''
On March 13, 2012, the EPA issued a No Action Assurance (NAA) to
all owners and/or operators of existing industrial boilers and
commercial and institutional boilers at area sources of HAP emissions
stating that we would not enforce the requirement to conduct an initial
tune-up by March 21, 2012. The NAA was primarily based upon the EPA's
concern that sources were reporting a shortage of qualified individuals
to prepare boilers for tune-ups and then conduct those tune-ups by the
regulatory deadline, as well as upon the uncertainty in the regulated
community resulting from the pending reconsideration of the Area Source
Boiler Rule. The March 13, 2012, NAA states that it remains in effect
until either (1) 11:59 p.m. EDT, October 1, 2012, or (2) the effective
date of a final rule addressing the proposed reconsideration of the
Area Source Boiler Rule, whichever occurs earlier.
As the July 19, 2012, Notification of Compliance Status deadline
approached, a final rule addressing the proposed reconsideration of the
Area Source Boiler Rule had not been issued, and thus the NAA continued
to remain in effect. Nothing that the EPA learned since the issuance of
the original NAA letter led us to question our original concerns about
the feasibility of all sources timely completing an initial tune-up.
Further, sources that did not complete a tune-up could not certify that
they conducted one. Thus, on July 18, 2012, the EPA extended the NAA
for sources required to complete an initial tune-up by March 21, 2012,
to also include the deadline for submitting the Notification of
Compliance Status regarding the initial tune-up. In addition, given
that no final rule addressing the proposed reconsideration of the Area
Source Boiler Rule had been issued as of July 18, 2012, the pending
reconsideration continued to create uncertainty in the regulated
community. Thus, the NAA letter also amended the expiration date of the
March 13, 2012, NAA, such that the NAA would remain in effect until
either (1) 11:59 p.m. EST, December 31, 2012, or (2) the effective date
of a final rule addressing the proposed reconsideration of the Area
Source Boiler Rule, whichever occurs earlier.
This final rule revises the compliance date for existing affected
boilers subject to a tune-up from March 21, 2012, to March 21, 2014.
The July 19, 2012, deadline for submitting the Notification of
Compliance Status regarding the initial tune-up is reset to July 19,
2014, as a result of revising the compliance date for existing affected
boilers subject to a tune-up to March 21, 2014. Owners or operators
that had not yet conducted their boiler tune-up, but submitted a
Notification of Compliance Status by July 19, 2012, simply to notify
the EPA
[[Page 7498]]
that the tune-up had not been completed, will need to submit a revised
Notification of Compliance Status after their boiler tune-up is
conducted.
IV. Summary of Significant Changes Since Proposed Action on
Reconsideration
Numerous changes are being made to the March 2011 final rule based
on the public comments received. Most of the changes are editorial to
clarify applicability and implementation issues raised by the
commenters. The public comments received on the proposed changes and
the responses to them can be viewed in the memorandum ``Summary of
Public Comments and Responses for: National Emission Standards for
Hazardous Air Pollutants for Area Sources: Industrial, Commercial, and
Institutional Boilers'' located in the docket.
A. Applicability
Since proposal, changes to the applicability of this final rule
have been made.
1. Dual-Fuel Fired Boilers
The March 2011 final rule includes as a new affected source a
boiler that commences fuel switching from natural gas to solid fossil
fuel, biomass, or liquid fuel after June 4, 2010. For example, under
the March 2011 final rule, if an unaffected gas-fired boiler currently
burns oil as allowed under the definition of gas-fired boiler, but
after June 4, 2010 burns oil for reasons not allowed under the
definition of gas-fired, these boilers would become new affected oil-
fired units. The December 2011 reconsideration action did not propose
any revisions to the provisions regarding boilers that fuel switch
after June 4, 2010. However, the EPA has been made aware through public
comments that many dual-fuel fired units presently burn primarily
natural gas with limited or no amounts of oil, and that these units may
want to burn oil in the future for reasons not allowed under subpart
JJJJJJ's definition of gas-fired (e.g. cost). Under the March 2011
final rule, such an existing dual-fuel gas-fired boiler that wanted to
avoid being subject to the new source requirements would notify as an
existing oil-fired unit and be subject to the requirements for existing
oil-fired boilers.
We received public comments regarding rule applicability and
compliance requirements for these existing dual-fuel fired boilers. One
commenter asserted that regardless of the fuel capability identified in
an initial notification, the distinction between a new source and an
existing source should only be made based upon a source's capability to
burn a particular fuel as of the effective date of the rule. The
commenter explained that many facilities have boilers that can burn
either gas or liquid and, because the price of gas is currently lower
than the price of most liquid fuels, they likely are currently firing
gas during normal operation, with liquid being fired only during
periods of curtailment. The commenter pointed out that, in the future,
the price of liquid fuel may be lower than the price of gaseous fuel,
and facilities may want to preferentially burn liquid fuel over gas
fuel. The commenter asserted that a change in the fuel from the initial
notification should not, in and of itself, reclassify a source as a new
source for purposes of subpart JJJJJJ. Further, the commenter asserted
that their interpretation is comparable to the fuel switching
provisions in the EPA's NSPS and PSD regulations. The same commenter
asserted that if a source already has oil or alternate fuel capability,
then that source would not be commencing construction or making a
change to the source. The commenter explained that many of these
facilities with boilers capable of burning fuel oil as a back-up for
natural gas may not have submitted an initial notification since
gaseous fuel-fired boilers that only burn liquid during periods of
curtailment are not covered by the Area Source Boiler Rule. The
commenter maintained the EPA's guidance, that a dual-fuel fired boiler
that fails to file an initial notification and then plans to burn oil
in the future would be considered to be a new source, appears to be
contrary to regulatory text stating that an affected source is a new
source if construction or reconstruction of the affected source is
commenced after June 4, 2010 and the applicability criteria are met at
the time construction is commenced. The commenter suggested that the
EPA clarify that to become a new source, the source must be altered to
be capable of accommodating a new fuel, so that new sources are not
created simply by failing to submit an initial notification or a notice
of fuel switching for a unit that is already capable of accommodating
that fuel. Another commenter explained that owners and operators of
dual-fuel fired boilers anticipate firing natural gas for many years to
come, or until gas supply is temporarily curtailed outside of their
control or until such a time when fuel oil becomes more cost effective
to burn than gas. The commenter asserted that, based on common sense
and increased flexibility, these dual-fuel fired boilers normally
burning gas could not be considered subject to any oil-fired
requirements as long as they continue to fire only gas, except under
the regulation's stated exemptions for burning oil.
In addition to carefully considering the public comments received
regarding dual-fuel fired boilers, the EPA reconsidered its overall
intent with regard to existing dual-fuel fired boilers that fuel switch
after June 4, 2010. Consequently, in this final rule, we are revising
the provisions regarding existing boilers that fuel switch after June
4, 2010. This final rule amends 40 CFR 63.11194 to specify that an
existing dual-fuel fired boiler (i.e., commenced construction or
reconstruction on or before June 4, 2010) meeting the definition of
gas-fired boiler, as defined in 40 CFR 63.11237, that meets the
applicability requirements of subpart JJJJJJ after June 4, 2010 due to
a fuel switch from gaseous fuel to solid fossil fuel, biomass, or
liquid fuel is considered to be an existing source under this subpart
as long as the boiler was designed to accommodate the alternate fuel. A
new or reconstructed dual-fuel fired boiler (i.e., commenced
construction or reconstruction after June 4, 2010) meeting the
definition of gas-fired boiler, as defined in 40 CFR 63.11237, that
meets the applicability criteria of subpart JJJJJJ after June 4, 2010
due to a fuel switch from gaseous fuel to solid fossil fuel, biomass,
or liquid fuel is considered to be a new source under this subpart.
This revision maintains consistency with the rule's applicability
criteria for determining new versus existing sources, eliminates the
requirement that existing dual-fuel fired boilers notify as affected
sources although, at the time, they are not subject to subpart JJJJJJ,
and promotes flexibility in that these existing dual-fuel fired sources
that were designed to accommodate an alternate fuel may fire the
alternate fuel and move into subpart JJJJJJ without being subject to
the more stringent requirements for new boilers.
2. Residential Boilers
One commenter suggested that the definition of ``residential
boiler,'' as proposed, be revised to acknowledge the use of combined
heat and power systems which function with heat and/or hot water
systems. The EPA agrees and is amending the proposed definition to
clarify that a boiler that operates as part of a residential combined
heat and power system (and that meets other definitional requirements)
is a residential boiler. Another commenter explained that
[[Page 7499]]
historical buildings may be subdivided into more than four units but
boilers serving those units should still be considered residential
boilers. We agree and, in this final rule, are amending the proposed
definition to clarify that a boiler serving a single unit residence
dwelling that has since been converted or subdivided into condominiums
or apartments may also be considered a residential boiler.
3. Temporary Boilers
One commenter supported the EPA's 12-month threshold above which
the boiler would no longer be considered temporary but pointed out that
a boiler used on a temporary basis during construction of a commercial
building may be needed for more than 12 months due to the length of the
construction period. The commenter suggested that the definition of
temporary boiler, as proposed, be revised to allow owners or operators
to petition for an extension beyond 12 months. We agree with the
commenter and, in this final rule, are amending the proposed definition
to allow an owner or operator to submit to their regulatory agency a
petition for an extension beyond 12 months. Another commenter suggested
that the EPA expand on the intent of ``location'' in the definition of
``temporary boiler.'' We are amending the proposed definition to
clarify that ``location'' means ``location within the facility.'' This
clarification will allow a boiler to be moved from one location to
another within a facility and be considered a different temporary
boiler (i.e., a new time period begins) as long as the boiler does not
continue to perform the same or similar function and to serve the same
electricity, steam, and/or hot water system. Another commenter pointed
out that our definition, as proposed, does not specify a time period
associated with the statement ``Any temporary boiler that replaces a
temporary boiler at a location within the facility and performs the
same or similar function will be included in calculating the
consecutive time period.'' The commenter explained that it is not
unusual for a temporary boiler to be used for short periods during
turnarounds or other maintenance activities that recur several years
apart. Under the proposal, these boilers would not be considered
temporary because each boiler replaces the previous one and performs
the same function, even though there is a multi-year gap between the
occurrences. The commenter suggested that replacements that occur after
a gap of at least one year should not be considered consecutive for the
purposes of the definition. We agree with the commenter and are
amending numbered paragraph (2) in the proposed definition of
``temporary boiler'' such that it specifies that ``Any temporary boiler
that replaces a temporary boiler at a location within the facility and
performs the same or similar function will be included in calculating
the consecutive time period unless there is a gap in operation of 12
months or more.''.
4. Seasonal Boilers
Several commenters explained that boilers subject to semi-annual
testing requirements would not meet the proposed 7 consecutive month
shutdown criteria, but otherwise would be considered seasonal boilers.
Commenters suggested that seasonal boiler be defined to allow periodic
testing during the 7-month shutdown period. We agree with the
commenters and, in this final rule, are revising the proposed
definition of seasonal boiler to allow for a combined total of 15 days
of use during the shutdown period for periodic testing.
Another commenter pointed out that the EPA's seasonal boiler
definition, as proposed, would potentially allow more regular use. The
commenter specifically suggested that the proposed definition be
revised to clarify that there must be a 7 consecutive month shutdown
every 12 months. It was the EPA's intent that the shutdown period of at
least 7 consecutive months be on a 12-month basis. In response to this
comment, we are clarifying in the definition of seasonal boiler that
the shutdown must be for a period of at least 7 consecutive months (or
210 consecutive days) each 12-month period.
5. Limited-Use Boilers
Several commenters asserted that the EPA should also include a
limited-use subcategory in the area source rule for the same reasons we
determined a seasonal boiler subcategory was appropriate. Commenters
suggested that we should apply the same 5-year tune-up cycle for
limited-use units such as auxiliary boilers that we proposed for
seasonally-operated units and small oil-fired units. Commenters
explained that in the electric utility industry, auxiliary boilers are
typically used to generate the steam necessary to bring a main EGU on
line during startup and, since auxiliary boilers are primarily operated
during unit startup, operation for many of these boilers is typically
very limited and sporadic. Commenters also pointed out that the Major
Source Boiler Rule includes a limited-use subcategory.
The EPA has determined that a limited-use subcategory is
appropriate and is including a limited-use subcategory in this final
Area Source Boiler Rule. Specifically, a limited-use boiler is defined
in this final rule to mean any boiler that burns any amount of solid or
liquid fuels and has a federally enforceable average annual capacity
factor of no more than 10 percent. We are using a capacity-factor
approach for the same reasons that the approach is being used in the
Major Source Boiler Rule. A capacity-factor approach allows operational
flexibility for units that operate on standby mode or low loads for
periods longer than would be allowed under an approach that limited
hours of operation (e.g., the 876 hours per year included in the
proposed limited-use definition for major source boilers). The
operational flexibility associated with a capacity-factor approach can
be achieved without increasing emissions or harm to human health and
the environment. Units operating at 10 percent load for 8,760 hours per
year would emit the same amount of emissions as units operating at full
load for 876 hours per year. Further, it is technically infeasible to
test these limited-use boilers since these units serve as back-up
energy sources and their operating schedules can be intermittent and
unpredictable.
This final rule specifies that limited-use boilers are required to
complete a tune-up every 5 years. Boilers that operate no more than 10
percent of the year (i.e., a limited-use boiler) would operate for no
more than 6 months in between tune-ups on a 5-year tune-up cycle. The
brief period of operations is even less than the number of operating
months that seasonal boilers and full-time boilers will operate between
tune-ups. The irregular schedule of operations also makes it difficult
to schedule more frequent tune-ups. We believe that establishing a
limited-use subcategory is reasonable.
6. Alternative PM Emission Control for Certain Oil-Fired Boilers
The EPA received a number of comments urging that we provide an
exemption from the PM limit for units burning low-sulfur liquid fuel as
is provided in subpart Dc of 40 CFR part 60 (standards of performance
for new small industrial-commercial-institutional steam generating
units). Commenters asserted that such an exemption is justified since
the low sulfur content indicates low PM emissions and that boilers
firing low-sulfur liquid fuel should only be subject to a requirement
to maintain records documenting the liquid fuel fired. We agree burning
low-sulfur liquid fuel can be an alternative method of meeting GACT for
PM. We are amending 40 CFR
[[Page 7500]]
63.11210 to specify that new or reconstructed oil-fired boilers that
combust only oil that contains no more than 0.50 weight percent sulfur
or a mixture of 0.50 weight percent sulfur oil with other fuels not
subject to a PM emission limit under this subpart and that do not use a
post-combustion technology (except a wet scrubber) to reduce PM or
sulfur dioxide emissions meet GACT for PM providing the type of fuel
combusted is monitored and recorded on a monthly basis. Further, we are
specifying that if you intend to burn a new type of fuel or fuel
mixture that does not meet the requirements of this paragraph, you must
conduct a performance test within 60 days of burning the new fuel.
B. Tune-Up Requirements
1. Boilers With Oxygen Trim Systems
In this final rule, the EPA is adding to the types of boilers that
must conduct a tune-up every 5 years boilers that have an oxygen trim
system that maintain an optimum air-to-fuel ratio that would otherwise
be subject to biennial tune-ups. These units do not need to be tuned as
frequently as other types of boilers because the trim system is
designed to maintain an optimum air-to-fuel ratio which is the purpose
of a tune-up.
2. Initial Compliance for Existing Boilers
The EPA is revising the initial compliance date for existing
boilers subject to the work practice or management practice standard of
a tune-up. Under the proposed rule, owners and operators of existing
affected boilers would have had to comply with the final rule by March
21, 2013. We solicited comments on whether to extend the compliance
date to March 21, 2014. We received no comments objecting to either of
these dates. Support for an extension until 2014 came from a variety of
stakeholders affected by the rule. Therefore, this final rule requires
that if you own or operate an existing boiler subject to a work
practice or management practice standard of a tune-up, you must comply
with the final rule no later than March 21, 2014.
3. Compliance Demonstration
We solicited comment on the requirements for demonstrating
compliance with the work practice and management practice tune-up
standards, with one focus on clarifying how to measure CO. Commenters
requested that we clarify that CO measurements may be taken with a
portable CO analyzer. We agree that this clarification is appropriate
and are including this clarification in this final rule.
C. Energy Assessment
The EPA received a number of comments regarding the energy
assessment requirements and in this final rule is making a series of
changes to the energy assessment provisions and related definitions
that clarify terms used and better set the scope of the assessment.
In this final rule, we are revising the definition of energy
assessment by providing a duration for performing the energy assessment
for numbered paragraph (3) in the definition of ``energy assessment''
in 40 CFR 63.11237 for facilities with units with greater than 1 TBtu/
yr heat input capacity to specify time duration/size ratio and are
including a cap to the maximum number of on-site technical hours that
should be used in the energy assessment. The energy assessment for
facilities with affected boilers and process heaters with greater than
1.0 TBtu/yr heat input capacity will be up to 24 on-site technical
labor hours in length for the first TBtu/yr plus 8 technical labor
hours for every additional 1.0 TBtu/yr not to exceed 160 technical
hours, but may be longer at the discretion of the owner or operator.
The revised definition of energy assessment also clarifies our
intentions that the scope of assessment is based on energy use by
discrete segments of a facility, which could vary significantly
depending on the site and its complexity, and not by a total
aggregation of all individual energy using elements of a facility. We
are adding the following language, as paragraph (4), to the ``energy
assessment'' definition to help resolve current problems and allow for
more streamlined assessments:
``(4) The on-site energy use systems serving as the basis for the
percent of affected boiler(s) energy output in paragraphs (1), (2), and
(3) of this definition may be segmented by production area or energy
use area as most logical and applicable to the specific facility being
assessed (e.g., product X manufacturing area; product Y drying area;
Building Z).''
In this final rule, we are revising 40 CFR 63.11201 and Table 2 to
subpart JJJJJJ to allow a source that is operating under an energy
management program established through energy management systems
compatible with ISO 50001, that includes the affected boilers, by March
21, 2014, to satisfy the energy assessment requirement. In addition, we
are clarifying that energy assessor approval and qualification
requirements are waived in instances where an energy assessment
completed on or after January 1, 2008 meets or is amended to meet the
energy assessment requirements in this final rule by March 21.
The definition of ``boiler system'' is being revised in this final
rule to clarify that it means the boiler and associated components
directly connected to and serving the energy use systems.
The definition of ``energy use system'' is also being revised in
this final rule to clarify that energy use systems are only those on-
site systems using energy clearly produced by affected boilers.
D. Clarification of Oxygen Concentration Operating Limits
We are clarifying in this final rule that operating limits for
oxygen concentration must be at or above the minimum established during
a performance stack test. We are also clarifying that these limits are
applicable when the unit is firing the fuel or fuel mixture utilized
during the CO performance test.
E. Definitions Regarding Averaging Times
The EPA received comments requesting that we clarify that periods
of startup and shutdown are excluded from calculation of the arithmetic
mean in the definitions of ``30-day rolling average'' and ``daily block
average.'' We agree with the commenters and, in this final rule, are
revising the definitions accordingly.
F. Fuel Sampling Frequency
The EPA is amending the fuel sampling requirements in 40 CFR
63.11220(c) because we realized that when performance stack testing
requirements were revised in the March 2011 final rule we neglected to
revise the fuel analysis requirements. In this final rule, we are
specifying that the owner or operator does not need to conduct further
fuel analysis sampling if, when demonstrating initial compliance with
the Hg emission limit, the Hg constituents in the fuel or fuel mixture
are measured to be equal to or less than half of the Hg emission limit.
If, when demonstrating initial compliance, the Hg constituents in the
fuel or fuel mixture are greater than half of the Hg emission limit,
the owner or operator must conduct quarterly sampling.
G. Performance Testing Frequency
The EPA is amending the PM performance testing requirements in 40
CFR 63.11220(b) to specify that the
[[Page 7501]]
owner or operator of an affected boiler does not need to conduct
further PM emission testing if, when demonstrating initial compliance
with the PM emission limit, the performance test results show that the
PM emissions are equal to or less than half of the PM emission limit.
The owner or operator must continue to comply with all applicable
operating limits and monitoring requirements. If the initial
performance test results show that the PM emissions are greater than
half of the PM emission limit, the owner or operator must conduct
subsequent performance tests as specified in 40 CFR 63.11220(a).
With respect to the reconsideration issue regarding the GACT-based
PM standards for new oil-fired boilers, we received comments asserting
that the most effective control strategy for small oil-fired boilers is
the tune-up required by the standards and that establishing a PM limit
for those boilers between 10 MMBtu/hr and 30 MMBtu/hr just ensures that
those boilers will do stack testing demonstrating that the boilers are
in compliance without the need for controls; a fact already known.
Commenters also asserted that establishing a PM limit imposes a stack
test obligation on small facilities with the least resources to deal
with the testing.
We have reviewed the comments and are not eliminating or revising
the PM limit for new oil-fired boilers with heat input capacity between
10 MMBtu/hr and 30 MMBtu/hr. We do however, believe that adjustments to
the PM performance test frequency as described above are appropriate
for boilers that demonstrate during their initial performance test that
their PM emissions are equal to or less than half of the PM limit. We
believe that the performance test adjustment should not be potentially
applicable to only new oil-fired boilers with heat input capacity
between 10 MMBtu/hr and 30 MMBtu/hr, but to all new boilers. Owners or
operators of boilers whose initial performance test results show that
their PM emissions are equal to or less than half of the PM emission
limit and, thus, do not need to conduct further PM emissions testing,
must continue to comply with all applicable operating limits and
monitoring requirements to ensure that there are no changes in
operation of the boiler or air pollution control equipment that could
increase emissions. This adjustment in PM performance test frequency
will potentially reduce the burden on small entities operating boilers
that meet the adjustment criteria.
H. Startup and Shutdown Definitions
A number of commenters indicated that the proposed load
specifications (i.e., 25 percent load) within the definitions of
``startup'' and ``shutdown'' were inconsistent with either safe or
normal (proper) operation of the various types of boilers encountered
within the source category. As the basis for defining periods of
startup and shutdown, a number of commenters suggested alternative load
specifications based on the specific considerations of their boilers;
other commenters suggested the achievement of various steady-state
conditions.
We have reviewed these comments and believe adjustments are
appropriate in the definitions of ``startup'' and ``shutdown.'' These
adjustments are tailored for industrial boilers and are consistent with
the definitions of ``startup'' and ``shutdown'' contained in the 40 CFR
part 63, subpart A General Provisions. We believe these revised
definitions address the comments and are rational based on the fact
that industrial boilers function to provide steam or, in the case of
cogeneration units, electricity. Therefore, industrial boilers should
be considered subject to applicable standards at all times steam of the
proper pressure, temperature and flow rate is being provided to a
common header system or energy user(s) for use as either process steam
or for the cogeneration of electricity. The definitions of ``startup''
and ``shutdown'' have been revised in this final rule as follows:
Startup means either the first-ever firing of fuel in a boiler
for the purpose of supplying steam or heat for heating and/or
producing electricity, or for any other purpose, or the firing of
fuel in a boiler after a shutdown event for any purpose. Startup
ends when any of the steam or heat from the boiler is supplied for
heating and/or producing electricity, or for any other purpose.
Shutdown means the cessation of operation of a boiler for any
purpose. Shutdown begins either when none of the steam or heat from
the boiler is supplied for heating and/or producing electricity, or
for any other purpose, or at the point of no fuel being fired in the
boiler, whichever is earlier. Shutdown ends when there is no steam
and no heat being supplied and no fuel being fired in the boiler.
I. Notifications
1. Initial Notification
The EPA has been made aware that there are many affected boilers at
area sources that are just becoming aware, or are not yet aware, that
they are subject to emission standards. Thus, we are amending 40 CFR
63.11225(a)(2) to allow these sources until January 20, 2014 to submit
their Initial Notification.
2. Notification of Fuel Change, Physical Change, or Permit Limit
The notification requirement in 40 CFR 63.11225(g) of the final
rule for instances when a change in fuel or a physical change to a
boiler results in the applicability of a different subcategory or a
change out of subpart JJJJJJ is being revised. Under the proposed
reconsideration action, a facility would have been required to provide
30 days prior notice of the date upon which the change was scheduled to
occur. Commenters explained that an advanced notification requirement
would delay such a change if the owner or operator decided to
immediately make a change (e.g., switch to 100 percent natural gas) and
could potentially restrict flexibility in manufacturing operations, and
suggested that the owner or operator be allowed to make notification
within 30 days after the change has occurred. We agree that
notification within 30 days after a change that results in
applicability of a different subcategory or a change out of subpart
JJJJJJ will provide the EPA or state/local agency with the required
information within a reasonable timeframe. Thus, in this final rule, we
are requiring facilities making these types of changes to provide
notification within 30 days following the change. The notification
requirement in 40 CFR 63.11225(g) is also being amended to clarify that
it includes affected boilers that switch fuels or make a physical
change to the boiler and the fuel switch or change results in the
applicability of a different subcategory within subpart JJJJJJ, in the
boiler becoming subject to subpart JJJJJJ, or in the boiler switching
out of subpart JJJJJJ due to a change to 100 percent natural gas, as
well as affected boilers that take a permit limit that results in the
applicability of subpart JJJJJJ. Commenters requested that we make this
clarification and we agree that it is appropriate.
J. Miscellaneous Definitions
In this final rule, we are revising some definitions and adding
others to help affected sources determine their applicability.
Specifically, definitions have been added for the terms ``10-day
rolling average,'' ``30-day rolling average,'' ``Annual heat input,''
``Biodiesel,'' ``Calendar year,'' ``Common stack,'' ``Daily block
average,'' ``Distillate oil,'' ``Electric boiler,'' ``Electric utility
steam generating unit (EGU),'' ``Energy management program,''
``Fluidized bed boiler,'' ``Fluidized bed combustion,'' ``Hourly
average,'' ``Limited-use boiler,'' ``Load fraction,''
[[Page 7502]]
``Minimum scrubber pressure drop,'' ``Minimum sorbent injection rate,''
``Minimum total secondary electric power,'' ``Operating day,'' ``Oxygen
analyzer system,'' ``Oxygen trim system,'' ``Process heater,''
``Regulated gas stream,'' ``Residential boiler,'' ``Residual oil,''
``Seasonal boiler,'' ``Shutdown,'' ``Solid fuel,'' ``Startup,''
``Temporary boiler,'' ``Tune-up,'' ``Vegetable oil,'' ``Voluntary
Consensus Standards (VCS),'' and ``Wet scrubber.''
Definitions revised to clarify the term include ``Bag leak
detection system,'' ``Biomass subcategory,'' ``Boiler,'' ``Boiler
system,'' ``Deviation,'' ``Dry scrubber,'' ``Electrostatic precipitator
(ESP),'' ``Energy assessment,'' ``Energy use system,'' ``Federally
enforceable,'' ``Gas-fired boiler,'' ``Heat input,'' ``Hot water
heater,'' ``Institutional boiler,'' ``Liquid fuel,'' ``Minimum
activated carbon injection rate,'' ``Minimum oxygen level,'' ``Minimum
scrubber liquid flow rate,'' ``Natural gas,'' ``Oil subcategory,''
``Particulate matter,'' ``Period of gas curtailment or supply
interruption,'' ``Qualified Energy Assessor,'' and ``Waste heat
boiler.''
V. Other Actions the EPA Is Taking
Section 307(d)(7)(B) of the CAA states that ``[o]nly an objection
to a rule or procedure which was raised with reasonable specificity
during the period for public comment (including any public hearing) may
be raised during judicial review. If the person raising an objection
can demonstrate to the Administrator that it was impracticable to raise
such objection within such time or if the grounds for such objection
arose after the period for public comment (but within the time
specified for judicial review) and if such objection is of central
relevance to the outcome of the rule, the Administrator shall convene a
proceeding for reconsideration of the rule and provide the same
procedural rights as would have been afforded had the information been
available at the time the rule was proposed. If the Administrator
refuses to convene such a proceeding, such person may seek review of
such refusal in the United States court of appeals for the appropriate
circuit (as provided in subsection (b)).''
As to the first procedural criterion for reconsideration, a
petitioner must show why the issue could not have been presented during
the comment period, either because it was impracticable to raise the
issue during that time or because the grounds for the issue arose after
the period for public comment (but within 60 days of publication of the
final action). The EPA is denying the petitions for reconsideration of
five issues because this criterion has not been met. In many cases, the
petitions reiterate comments made on the proposed June 2010 rule during
the public comment period for that rule. On those issues, the EPA
responded to those comments in the March 2011 final rule, and made
appropriate revisions to the proposed rule after consideration of
public comments received. It is well established that an agency may
refine its proposed approach without providing an additional
opportunity for public comment. See Community Nutrition Institute v.
Block, 749 F.2d 50, 58 (DC Cir. 1984) and International Fabricare
Institute v. EPA, 972 F.2d 384, 399 (DC Cir. 1992) (notice and comment
is not intended to result in ``interminable back-and-forth[,]'' nor is
agency required to provide additional opportunity to comment on its
response to comments) and Small Refiner Lead Phase-Down Task Force v.
EPA, 705 F.2d 506, 547 (DC Cir. 1983) (``notice requirement should not
force an agency endlessly to repropose a rule because of minor
changes'')
In the EPA's view, an objection is of central relevance to the
outcome of the rule only if it provides substantial support for the
argument that the promulgated regulation should be revised. See Union
Oil v. EPA, 821 F.2d 768, 683 (DC Cir. 1987) (court declined to remand
rule because petitioners failed to show substantial likelihood that
final rule would have been changed based on information in petition).
See also the EPA's Denial of the Petitions to Reconsider the
Endangerment and Cause or Contribute Findings for Greenhouse Gases
under Section 202 of the Clean Air Act, 75 FR at 49556, 49561 (August
13, 2010). See also, 75 FR at 49556, 49560-49563 (August 13, 2010) and
76 FR at 4780, 4786--4788 (January 26, 2011) for additional discussion
of the standard for reconsideration under CAA section 307(d)(7)(B).
We are denying reconsideration on the following five issues
contained in the petitions for reconsideration because they failed to
meet the standard described above for reconsideration under CAA section
307(d)(7)(B). Specifically, on these issues, the petitioner has failed
to show the following: That it was impracticable to raise their
objections during the comment period or that the grounds for their
objections arose after the close of the comment period; and/or that
their concern is of central relevance to the outcome of the rule.
Therefore, the EPA is denying the petitions for reconsideration on the
issues for the reasons described below.
Issue: Use of RDL Is Unlawful
The petitioner (Sierra Club) objected to the EPA establishing a
MACT floor emission limit at a level equal to three times the RDL as
being unlawful and arbitrary. This issue is not of central relevance to
the outcome of this final rule. The final emission limits in this rule
are based on the UPL at a confidence interval of 99 percent. The RDL
analysis was not used in this final rule.
Issue: MACT Floor for Existing Sources Must Reflect Average Performance
of the Top 12 Percent of Units
The petitioner (Sierra Club) stated that the MACT floor for
existing sources must reflect the average performance of the top 12
percent of units. The petitioner has not demonstrated that it lacked
the opportunity to comment on the EPA's MACT floor analysis. The
methods used to compute the MACT floors were subject to notice and
comment. Rationale and responses to comments on the MACT floor
methodology were provided at 75 FR 31904, June 4, 2010; 76 FR 15571,
March 21, 2011. Therefore, the EPA is denying the request for
reconsideration.
Issue: Consider a De Minimis Size Threshold
The petitioners (American Petroleum Institute, National
Petrochemical and Refiners Association, Alaska Oil and Gas Association)
requested that the EPA consider a de minimis size threshold using
guidelines from insignificance thresholds authorized under CAA part 71.
The EPA is denying the request for reconsideration on this issue. In
the June 2010 proposed rule, it was readily apparent that we were not
establishing de minimis size thresholds in the area source rulemaking.
We received multiple comments on this issue and responded to them in
the response to comments document for the March 2011 final rule. The
issue on which petitioners seek reconsideration was one that could have
been raised during the comment period and thus does not meet the
requirements for reconsideration. Therefore, the EPA is denying this
request for reconsideration.
Issue: MACT Standards Must Be Set for All HAP
The petitioner (Sierra Club) asserted that MACT standards must be
set for all HAP including HAP not listed in CAA section 112(c)(6). The
EPA is denying the request for reconsideration on this issue. We
disagree with the petitioner that the EPA must issue emission standards
for all HAP. MACT standards have been set for Hg and CO, as a
[[Page 7503]]
surrogate for POM emissions, but the EPA does not interpret CAA section
112(c)(6) to compel regulation of all HAP emitted by area sources. The
EPA's position on this issue was clear in the proposed rule (75 FR
31900, 31904, 31918). This commenter raised this issue in its comments
(76 FR 15567, March 21, 2011). Not only did the petitioner have an
opportunity to present its theory in its comments, but also it did so.
Issue: CO Is Not a Valid Surrogate for POM
The petitioner (Sierra Club) requested that the EPA remove the CO
standard as a surrogate for POM and instead adopt a numeric limit for
POM because CO is not an appropriate surrogate. The EPA is denying the
request for reconsideration on this issue. While the EPA disagrees with
the petitioner's argument regarding the suitability of CO as a
surrogate for POM, the petitioner has not demonstrated that it lacked
the opportunity to comment on this issue. The EPA revised the final CO
emission limit to ensure a more accurate correlation between POM and CO
levels. The EPA made its position on this issue clear and explained the
agency's basis for concluding that CO was an appropriate surrogate in
the proposed rule (75 FR 31900, 31904, June 4, 2010). The petitioner
raised this issue in its comments (Document ID: EPA-HQ-OAR-2006-0790-
1982, Comments of Earthjustice, Sierra Club, Clean Air Task Force, and
Natural Resources Defense Council, p. 4). Therefore, the EPA is denying
the request for reconsideration.
VI. Impacts Associated With This Final Rule
The amendments contained in this final action are corrections that
are intended to clarify, but not change, the coverage of the final
rule. The clarifications and corrections should make it easier for
owners and operators and for local and state authorities to understand
and implement the requirements. The final amendments will not affect
the estimated emission reductions, control costs or the benefits of the
rule in substance. The amendments do not impose any additional
regulatory requirements beyond those imposed by the previously
promulgated boiler area source rule and, in fact, will result in a
decrease in the burden on small facilities as a result of the reduction
in the frequency of conducting tune-ups for seasonal boilers, limited-
use boilers, small (equal to or less than 5 MMBtu/hr) oil-fired boilers
and boilers using an oxygen trim system that maintain an optimum air-
to-fuel ratio. Additionally, the burden will be reduced on facilities
with existing large boilers that currently operate under an energy
management program established through energy management systems
compatible with ISO 50001, that includes the affected boilers, because
a one-time energy assessment will not be required. Burden will also be
reduced on facilities with affected boilers that burn low-sulfur oil
because, in lieu of needing to meet an emission limit, we consider low-
sulfur oil combustion to be GACT for PM for those boilers. This change
should allow sources currently complying with 40 CFR 60 subpart Dc to
use the same compliance approach rather than needing to monitor limits.
Further reduction in burden will occur in instances where initial
compliance demonstrations with the Hg emission limit via fuel sampling
or with the PM emission limit via performance stack testing show that
the emissions are equal to or less than half the respective emission
limit because no further sampling or testing of those boilers will be
required.
As discussed in section III, the Hg emission limits for new and
existing large (10 MMBtu/hr or greater) coal-fired area source boilers
were revised because of an error discovered in the analysis conducted
for the final rule. This technical correction resulted in an increase
in the emission limit for Hg. As explained in the December 2011
proposal, we also revised our impacts analysis to be consistent with
emission factor changes made to the Major Source Boiler Rule. The
baseline emissions for area sources are calculated using the emission
factors developed for the Major Source Boiler Rule because of
insufficient data for area sources. Emission factor changes resulted in
a higher baseline emission for Hg from coal-fired area source boilers.
Consequently, the result of the increase in both baseline Hg emissions
and Hg emission limits is that the overall reduction in Hg emissions
does not change significantly from the estimated reduction for the
promulgated rule.
In summary, as compared to the control costs estimated for the
March 2011 final rule, this final rule will not result in any
meaningful change in the capital and annual cost due to the increase in
emission limits and the decrease in burden on small facilities.
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
Under section 3(f)(1) of Executive Order 12866 (58 FR 51735,
October 4, 1993), this action is a ``significant regulatory action''
because it is likely to raise novel legal or policy issues.
Accordingly, the EPA submitted this action to the OMB for review under
Executive Order 12866 and Executive Order 13563 (76 FR 3821, January
21, 2011), and any changes made in response to OMB recommendations have
been documented in the docket for this action.
B. Paperwork Reduction Act
This action does not impose an information collection burden. This
action results in no significant changes to the information collection
requirements of the promulgated rule and will have no increased impact
on the information collection estimate of projected cost and hour
burden made and approved by OMB. In fact, the reduction in tune-up
frequency for some boilers will result in less information collection
burden. Therefore, the information collection request has not been
revised. However, the OMB has previously approved the information
collection requirements contained in the existing regulation (40 CFR
part 63, subpart JJJJJJ) under the provisions of the Paperwork
Reduction Act, 44 U.S.C. 3501, et seq. and has assigned OMB control
number 2060-0668. The OMB control numbers for the EPA's regulations in
40 CFR are listed in 40 CFR part 9.
C. Regulatory Flexibility Act
The RFA generally requires an agency to prepare a regulatory
flexibility analysis of any rule subject to notice and comment
rulemaking requirements under the Administrative Procedure Act or any
other statute unless the agency certifies that the rule will not have a
significant economic impact on a substantial number of small
entities.\2\
[[Page 7504]]
The RFA also allows an agency to ``consider a series of closely related
rules as one rule for the purposes of sections'' 603 (initial
regulatory flexibility analysis) and 604 (final regulatory flexibility
analysis) in order to avoid ``duplicative action.'' 5 U.S.C. section
605(c). These amendments and notice of final action on reconsideration
are closely related to the final Area Source Boiler Rule, which the EPA
signed on February 21, 2011, and that took effect on May 20, 2011. The
EPA prepared a final regulatory flexibility analysis in connection with
the final Area Source Boiler Rule. Therefore, pursuant to section
605(c), the EPA is not required to complete a final regulatory
flexibility analysis for this rule (i.e., the amendments and final
action).
---------------------------------------------------------------------------
\2\ Small entities include small businesses, small
organizations, and small governmental jurisdictions. For purposes of
assessing the impacts of this final rule on small entities, small
entity is defined as: (1) A small business as defined by the Small
Business Administration size standards for small businesses at 13
CFR 121.201 (less than 500, 750, or 1,000 employees, depending on
the specific NAICS Code under subcategory 325); (2) a small
governmental jurisdiction that is a government of a city, county,
town, school district or special district with a population of less
than 50,000; and (3) a small organization that is any not-for-profit
enterprise that is independently owned and operated and is not
dominant in its field.
---------------------------------------------------------------------------
The EPA has been concerned with potential small entity impacts
since it began developing the Area Source Boiler Rule. The EPA
conducted outreach to small entities and, pursuant to section 609 of
RFA, convened a Small Business Advocacy Review Panel (the Panel) on
January 22, 2009, to obtain advice and recommendations from small
entity representatives. Pursuant to the RFA, the EPA used the Panel's
report and prepared both an initial regulatory flexibility analysis and
a final regulatory flexibility analysis in connection with the closely
related final Area Source Boiler Rule. Convening an additional Panel
and preparing an additional final regulatory flexibility analysis would
be procedurally duplicative and is unnecessary given that the issues
here are within the scope of those considered by the Panel. Finally, we
note that this action, which amends the Area Source Boiler Rule, will
not impose any additional regulatory requirements beyond those imposed
by the previously promulgated Area Source Boiler Rule and, in fact, the
amendments will afford relief to some boilers.
D. Unfunded Mandates Reform Act
This action contains no new federal mandates under the provisions
of Title II of the UMRA of 1995, 2 U.S.C. 1531-1538 for state, local,
or tribal governments or the private sector. This action imposes no new
enforceable duty on any state, local, or tribal governments or the
private sector. Therefore, this action is not subject to the
requirements of sections 202 and 205 of the UMRA.
This action is also not subject to the requirements of section 203
of UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments. This rule finalizes
amendments to aid with compliance.
E. Executive Order 13132: Federalism
This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. This final rule will not impose new
direct compliance costs on state or local governments, and will not
preempt state law. Thus, Executive Order 13132 does not apply to this
action.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). It will not have
substantial new direct effects on tribal governments, on the
relationship between the federal government and Indian tribes, or on
the distribution of power and responsibilities between the federal
government and Indian tribes, as specified in Executive Order 13175.
Thus, Executive Order 13175 does not apply to this action.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
The EPA interprets Executive Order 13045 (62 FR 19885, April 23,
1997) as applying to those regulatory actions that concern health or
safety risks, such that the analysis required under section 5-501 of
the Order has the potential to influence the regulation. This action is
not subject to Executive Order 13045 because it is based solely on
technology performance.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action is not a ``significant energy action'' as defined in
Executive Order 13211 (66 FR 28355, May 22, 2001), because it is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy. We estimate no significant changes for
the energy sector for price, production, or imports.
I. National Technology Transfer and Advancement Act
Section 12(d) of the NTTAA of 1995, Public Law No. 104-113, 12(d)
(15 U.S.C. 272 note) directs the EPA to use VCS in its regulatory
activities, unless to do so would be inconsistent with applicable law
or otherwise impractical. VCS are technical standards (e.g., materials
specifications, test methods, sampling procedures, and business
practices) that are developed or adopted by VCS bodies. NTTAA directs
the EPA to provide Congress, through OMB, explanations when the agency
decides not use available and applicable VCS.
This action does not involve any new technical standards.
Therefore, the EPA did not consider the use of any VCS.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
The EPA has determined that this final rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because the level of
protection provided to human health or the environment through the
rule's requirements does not vary. Therefore, it does not have any
disproportionately high or adverse human health or environmental
effects on any population, including any minority or low-income
population.
K. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. The EPA will submit a report containing this rule and
other required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to
[[Page 7505]]
publication of the rule in the Federal Register. A Major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is a reconsideration of a previous action that
was a major rule under the CRA. However, today's action makes only
certain limited revisions to the March 2011 rule and those revisions do
not qualify as a major rule under the CRA. Therefore, this action is
not a ``major rule'' as defined by 5 U.S.C. 804(2). This rule will be
effective February 1, 2013.
List of Subjects in 40 CFR Part 63
Environmental protection, Administrative practice and procedure,
Air pollution control, Hazardous substances, Incorporation by
reference.
Dated: December 20, 2012.
Lisa P. Jackson,
Administrator.
For the reasons stated in the preamble, title 40, chapter I, part
63 of the Code of Federal Regulations is amended as follows:
PART 63--[AMENDED]
0
1. The authority citation for part 63 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart A--[Amended]
0
2. Section 63.14 is amended by:
0
a. Revising paragraphs (b)(19), (b)(23), (b)(35), (b)(40), (b)(69), and
(b)(70).
0
b. Removing and reserving paragraph (b)(53).
0
c. Adding paragraphs (b)(46), (b)(55), and (b)(76) through (83).
0
d. Adding paragraphs (p)(12) through (20).
0
e. Adding paragraph (r).
The revisions and additions read as follows:
Sec. 63.14 Incorporations by reference.
* * * * *
(b) * * *
(19) ASTM D95-05 (Reapproved 2010), Standard Test Method for Water
in Petroleum Products and Bituminous Materials by Distillation,
approved May 1, 2010, IBR approved for Sec. 63.10005(i) and table 6 to
subpart DDDDD.
* * * * *
(23) ASTM D4006-11, Standard Test Method for Water in Crude Oil by
Distillation, including Annex A1 and Appendix X1, approved June 1,
2011, IBR approved for Sec. 63.10005(i) and table 6 to subpart DDDDD.
* * * * *
(35) ASTM D6784-02 (Reapproved 2008) Standard Test Method for
Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas
Generated from Coal-Fired Stationary Sources (Ontario Hydro Method),
approved April 1, 2008, IBR approved for table 1 to subpart DDDDD of
this part, table 2 to subpart DDDDD of this part, table 5 to subpart
DDDDD, table 11 to subpart DDDDD of this part, table 12 to subpart
DDDDD of this part, table 13 to subpart DDDDD of this part, and table 4
to subpart JJJJJJ of this part.
* * * * *
(40) ASTM D396-10 Standard Specification for Fuel Oils, approved
October 1, 2010, IBR approved for Sec. 63.7575 and Sec. 6311237.
* * * * *
(46) ASTM D4606-03(2007), Standard Test Method for Determination of
Arsenic and Selenium in Coal by the Hydride Generation/Atomic
Absorption Method, approved October 1, 2007, IBR approved for table 6
to subpart DDDDD.
* * * * *
(55) ASTM D6357-11, Test Methods for Determination of Trace
Elements in Coal, Coke, and Combustion Residues from Coal Utilization
Processes by Inductively Coupled Plasma Atomic Emission Spectrometry,
approved April 1, 2011, IBR approved for table 6 to subpart DDDDD.
* * * * *
(69) ASTM D4057-06 (Reapproved 2011), Standard Practice for Manual
Sampling of Petroleum and Petroleum Products, including Annex A1,
approved June 1, 2011, IBR approved for Sec. 63.10005(i) and table 6
to subpart DDDDD.
(70) ASTM D4177-95 (Reapproved 2010), Standard Practice for
Automatic Sampling of Petroleum and Petroleum Products, including
Annexes A1 through A6 and Appendices X1 and X2, approved May 1, 2010,
IBR approved for Sec. 63.10005(i) and table 6 to subpart DDDDD.
* * * * *
(76) ASTM D6751-11b, Standard Specification for Biodiesel Fuel
Blend Stock (B100) for Middle Distillate Fuels, approved July 15, 2011,
IBR approved for Sec. 63.7575 and Sec. 63.11237.
(77) ASTM D975-11b, Standard Specification for Diesel Fuel Oils,
approved December 1, 2011, IBR approved for Sec. 63.7575.
(78) ASTM D5864-11 Standard Test Method for Determining Aerobic
Aquatic Biodegradation of Lubricants or Their Components, approved
March 1, 2011, IBR approved for table 6 to subpart DDDDD.
(79) ASTM D240-09 Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter, approved July 1, 2009,
IBR approved for table 6 to subpart DDDDD.
(80) ASTM D4208-02(2007) Standard Test Method for Total Chlorine in
Coal by the Oxygen Bomb Combustion/Ion Selective Electrode Method,
approved May 1, 2007, IBR approved for table 6 to subpart DDDDD.
(81) ASTM D5192-09 Standard Practice for Collection of Coal Samples
from Core, approved June 1, 2009, IBR approved for table 6 to subpart
DDDDD.
(82) ASTM D7430-11ae1, Standard Practice for Mechanical Sampling of
Coal, approved October 1, 2011, IBR approved for table 6 to subpart
DDDDD.
(83) ASTM D6883-04, Standard Practice for Manual Sampling of
Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles,
approved June 1, 2004, IBR approved for table 6 to subpart DDDDD.
* * * * *
(p) * * *
(12) Method 5050 (SW-846-5050), Bomb Preparation Method for Solid
Waste, Revision 0, September 1994, in EPA Publication No. SW-846, Test
Methods for Evaluating Solid Waste, Physical/Chemical Methods, Third
Edition IBR approved for table 6 to subpart DDDDD.
(13) Method 9056 (SW-846-9056), Determination of Inorganic Anions
by Ion Chromatography, Revision 1, February 2007, in EPA Publication
No. SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
(14) Method 9076 (SW-846-9076), Test Method for Total Chlorine in
New and Used Petroleum Products by Oxidative Combustion and
Microcoulometry, Revision 0, September 1994, in EPA Publication No. SW-
846, Test Methods for Evaluating Solid Waste, Physical/Chemical
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
(15) Method 1631 Revision E, Mercury in Water by Oxidation, Purge
and Trap, and Cold Vapor Atomic Absorption Fluorescence Spectrometry,
Revision E, EPA-821-R-02-019, August 2002, IBR approved for table 6 to
subpart DDDDD.
(16) Method 200.8, Determination of Trace Elements in Waters and
Wastes by Inductively Coupled Plasma--Mass Spectrometry, Revision 5.4,
1994, IBR approved for table 6 to subpart DDDDD.
(17) Method 6020A (SW-846-6020A), Inductively Coupled Plasma-Mass
Spectrometry, Revision 1, February 2007, in EPA Publication No. SW-846,
Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,
[[Page 7506]]
Third Edition, IBR approved for table 6 to subpart DDDDD.
(18) Method 6010C (SW-846-6010C), Inductively Coupled Plasma-Atomic
Emission Spectrometry, Revision 3, February 2007, in EPA Publication
No. SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
(19) Method 7060A (SW-846-7060A), Arsenic (Atomic Absorption,
Furnace Technique), Revision 1, September 1994, in EPA Publication No.
SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
(20) Method 7740 (SW-846-7740), Selenium (Atomic Absorption,
Furnace Technique), Revision 0, September 1986, in EPA Publication No.
SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
* * * * *
(r) The following material is available for purchase from the
Technical Association of the Pulp and Paper Industry (TAPPI), 15
Technology Parkway South, Norcross, GA 30092, (800) 332-8686, http://www.tappi.org.
(1) TAPPI T 266, Determination of Sodium, Calcium, Copper, Iron,
and Manganese in Pulp and Paper by Atomic Absorption Spectroscopy
(Reaffirmation of T 266 om-02), Draft No. 2, July 2006, IBR approved
for table 6 to subpart DDDDD.
(2) [Reserved]
Subpart JJJJJJ--[AMENDED]
0
3. Section 63.11194 is amended by revising paragraphs (a)(1), (c) and
(d), by redesignating paragraph (e) as paragraph (f) and by adding new
paragraph (e) to read as follows:
Sec. 63.11194 What is the affected source of this subpart?
(a) * * *
(1) The affected source of this subpart is the collection of all
existing industrial, commercial, and institutional boilers within a
subcategory, as listed in Sec. 63.11200 and defined in Sec. 63.11237,
located at an area source.
* * * * *
(c) An affected source is a new source if you commenced
construction of the affected source after June 4, 2010, and the boiler
meets the applicability criteria at the time you commence construction.
(d) An affected source is a reconstructed source if the boiler
meets the reconstruction criteria as defined in Sec. 63.2, you
commenced reconstruction after June 4, 2010, and the boiler meets the
applicability criteria at the time you commence reconstruction.
(e) An existing dual-fuel fired boiler meeting the definition of
gas-fired boiler, as defined in Sec. 63.11237, that meets the
applicability requirements of this subpart after June 4, 2010 due to a
fuel switch from gaseous fuel to solid fossil fuel, biomass, or liquid
fuel is considered to be an existing source under this subpart as long
as the boiler was designed to accommodate the alternate fuel.
* * * * *
0
4. Section 63.11195 is amended by revising the introductory text and
paragraphs (c) and (g) and by adding paragraphs (h) through (k) to read
as follows:
Sec. 63.11195 Are any boilers not subject to this subpart?
The types of boilers listed in paragraphs (a) through (k) of this
section are not subject to this subpart and to any requirements in this
subpart.
* * * * *
(c) A boiler required to have a permit under section 3005 of the
Solid Waste Disposal Act or covered by subpart EEE of this part (e.g.,
hazardous waste boilers), unless such units do not combust hazardous
waste and combust comparable fuels.
* * * * *
(g) Any boiler that is used as a control device to comply with
another subpart of this part, or part 60, part 61, or part 65 of this
chapter provided that at least 50 percent of the average annual heat
input during any 3 consecutive calendar years to the boiler is provided
by regulated gas streams that are subject to another standard.
(h) Temporary boilers as defined in this subpart.
(i) Residential boilers as defined in this subpart.
(j) Electric boilers as defined in this subpart.
(k) An electric utility steam generating unit (EGU) covered by
subpart UUUUU of this part.
0
5. Section 63.11196 is amended by revising paragraphs (a)(1) and (d) to
read as follows:
Sec. 63.11196 What are my compliance dates?
(a) * * *
(1) If the existing affected boiler is subject to a work practice
or management practice standard of a tune-up, you must achieve
compliance with the work practice or management practice standard no
later than March 21, 2014.
* * * * *
(d) If you own or operate an industrial, commercial, or
institutional boiler and would be subject to this subpart except for
the exemption in Sec. 63.11195(b) for commercial and industrial solid
waste incineration units covered by 40 CFR part 60, subpart CCCC or
subpart DDDD, and you cease combusting solid waste, you must be in
compliance with this subpart on the effective date of the waste to fuel
switch as specified in Sec. 60.2145(a)(2) and (3) of subpart CCCC or
Sec. 60.2710(a)(2) and (3) of subpart DDDD.
0
6. Section 63.11200 is revised to read as follows:
Sec. 63.11200 What are the subcategories of boilers?
The subcategories of boilers, as defined in Sec. 63.11237 are:
(a) Coal.
(b) Biomass.
(c) Oil.
(d) Seasonal boilers.
(e) Oil-fired boilers with heat input capacity of equal to or less
than 5 million British thermal units (Btu) per hour.
(f) Boilers with an oxygen trim system that maintains an optimum
air-to-fuel ratio that would otherwise be subject to a biennial tune-
up.
(g) Limited-use boilers.
0
7. Section 63.11201 is amended by revising paragraphs (b) and (d) to
read as follows:
Sec. 63.11201 What standards must I meet?
* * * * *
(b) You must comply with each work practice standard, emission
reduction measure, and management practice specified in Table 2 to this
subpart that applies to your boiler. An energy assessment completed on
or after January 1, 2008 that meets or is amended to meet the energy
assessment requirements in Table 2 to this subpart satisfies the energy
assessment requirement. A facility that operates under an energy
management program established through energy management systems
compatible with ISO 50001, that includes the affected units, also
satisfies the energy assessment requirement.
* * * * *
(d) These standards apply at all times the affected boiler is
operating, except during periods of startup and shutdown as defined in
Sec. 63.11237, during which time you must comply only with Table 2 to
this subpart.
0
8. Section 63.11205 is amended by revising paragraphs (b), (c)
introductory
[[Page 7507]]
text, (c)(1) introductory text, and (c)(1)(i) to read as follows:
Sec. 63.11205 What are my general requirements for complying with
this subpart?
* * * * *
(b) You must demonstrate compliance with all applicable emission
limits using performance stack testing, fuel analysis, or a continuous
monitoring system (CMS), including a continuous emission monitoring
system (CEMS), a continuous opacity monitoring system (COMS), or a
continuous parameter monitoring system (CPMS), where applicable. You
may demonstrate compliance with the applicable mercury emission limit
using fuel analysis if the emission rate calculated according to Sec.
63.11211(c) is less than the applicable emission limit. Otherwise, you
must demonstrate compliance using stack testing.
(c) If you demonstrate compliance with any applicable emission
limit through performance stack testing and subsequent compliance with
operating limits (including the use of CPMS), with a CEMS, or with a
COMS, you must develop a site-specific monitoring plan according to the
requirements in paragraphs (c)(1) through (3) of this section for the
use of any CEMS, COMS, or CPMS. This requirement also applies to you if
you petition the EPA Administrator for alternative monitoring
parameters under Sec. 63.8(f).
(1) For each CMS required in this section (including CEMS, COMS, or
CPMS), you must develop, and submit to the Administrator for approval
upon request, a site-specific monitoring plan that addresses paragraphs
(c)(1)(i) through (vi) of this section. You must submit this site-
specific monitoring plan, if requested, at least 60 days before your
initial performance evaluation of your CMS. This requirement to develop
and submit a site-specific monitoring plan does not apply to affected
sources with existing CEMS or COMS operated according to the
performance specifications under appendix B to part 60 of this chapter
and that meet the requirements of Sec. 63.11224.
(i) Installation of the CMS sampling probe or other interface at a
measurement location relative to each affected process unit such that
the measurement is representative of control of the exhaust emissions
(e.g., on or downstream of the last control device);
* * * * *
0
9. Section 63.11210 is amended by revising paragraphs (b) through (e)
and adding paragraphs (f) through (j) to read as follows:
Sec. 63.11210 What are my initial compliance requirements and by what
date must I conduct them?
* * * * *
(b) For existing affected boilers that have applicable emission
limits, you must demonstrate initial compliance with the applicable
emission limits no later than 180 days after the compliance date that
is specified in Sec. 63.11196 and according to the applicable
provisions in Sec. 63.7(a)(2), except as provided in paragraph (j) of
this section.
(c) For existing affected boilers that have applicable work
practice standards, management practices, or emission reduction
measures, you must demonstrate initial compliance no later than the
compliance date that is specified in Sec. 63.11196 and according to
the applicable provisions in Sec. 63.7(a)(2), except as provided in
paragraph (j) of this section.
(d) For new or reconstructed affected boilers that have applicable
emission limits, you must demonstrate initial compliance with the
applicable emission limits no later than 180 days after March 21, 2011
or within 180 days after startup of the source, whichever is later,
according to Sec. 63.7(a)(2)(ix).
(e) For new or reconstructed oil-fired boilers that combust only
oil that contains no more than 0.50 weight percent sulfur or a mixture
of 0.50 weight percent sulfur oil with other fuels not subject to a PM
emission limit under this subpart and that do not use a post-combustion
technology (except a wet scrubber) to reduce particulate matter (PM) or
sulfur dioxide emissions, you are not subject to the PM emission limit
in Table 1 of this subpart providing you monitor and record on a
monthly basis the type of fuel combusted. If you intend to burn a new
type of fuel or fuel mixture that does not meet the requirements of
this paragraph, you must conduct a performance test within 60 days of
burning the new fuel.
(f) For new or reconstructed affected boilers that have applicable
work practice standards or management practices, you are not required
to complete an initial performance tune-up, but you are required to
complete the applicable biennial or 5-year tune-up as specified in
Sec. 63.11223 no later than 25 months or 61 months, respectively,
after the initial startup of the new or reconstructed affected source.
(g) For affected boilers that ceased burning solid waste consistent
with Sec. 63.11196(d) and for which your initial compliance date has
passed, you must demonstrate compliance within 60 days of the effective
date of the waste-to-fuel switch as specified in Sec. 60.2145(a)(2)
and (3) of subpart CCCC or Sec. 60.2710(a)(2) and (3) of subpart DDDD.
If you have not conducted your compliance demonstration for this
subpart within the previous 12 months, you must complete all compliance
demonstrations for this subpart before you commence or recommence
combustion of solid waste.
(h) For affected boilers that switch fuels or make a physical
change to the boiler that results in the applicability of a different
subcategory within subpart JJJJJJ or the boiler becoming subject to
subpart JJJJJJ, you must demonstrate compliance within 180 days of the
effective date of the fuel switch or the physical change. Notification
of such changes must be submitted according to Sec. 63.11225(g).
(i) For boilers located at existing major sources of HAP that limit
their potential to emit (e.g., make a physical change or take a permit
limit) such that the existing major source becomes an area source, you
must comply with the applicable provisions as specified in paragraphs
(i)(1) through (3) of this section.
(1) Any such existing boiler at the existing source must
demonstrate compliance with subpart JJJJJJ within 180 days of the later
of March 21, 2014 or upon the existing major source commencing
operation as an area source.
(2) Any new or reconstructed boiler at the existing source must
demonstrate compliance with subpart JJJJJJ within 180 days of the later
of March 21, 2011 or startup.
(3) Notification of such changes must be submitted according to
Sec. 63.11225(g).
(j) For existing affected boilers that have not operated between
the effective date of the rule and the compliance date that is
specified for your source in Sec. 63.11196, you must comply with the
applicable provisions as specified in paragraphs (j)(1) through (3) of
this section.
(1) You must complete the initial compliance demonstration, if
subject to the emission limits in Table 1 to this subpart, as specified
in paragraphs (a) and (b) of this section, no later than 180 days after
the re-start of the affected boiler and according to the applicable
provisions in Sec. 63.7(a)(2).
(2) You must complete the initial performance tune-up, if subject
to the tune-up requirements in Sec. 63.11223, by following the
procedures described in Sec. 63.11223(b) no later than 30 days after
the re-start of the affected boiler.
(3) You must complete the one-time energy assessment, if subject to
the energy assessment requirements specified in Table 2 to this
subpart, no
[[Page 7508]]
later than the compliance date specified in Sec. 63.11196.
0
10. Section 63.11211 is amended by revising paragraphs (a), (b)(1), and
(b)(2) to read as follows:
Sec. 63.11211 How do I demonstrate initial compliance with the
emission limits?
(a) For affected boilers that demonstrate compliance with any of
the emission limits of this subpart through performance (stack)
testing, your initial compliance requirements include conducting
performance tests according to Sec. 63.11212 and Table 4 to this
subpart, conducting a fuel analysis for each type of fuel burned in
your boiler according to Sec. 63.11213 and Table 5 to this subpart,
establishing operating limits according to Sec. 63.11222, Table 6 to
this subpart and paragraph (b) of this section, as applicable, and
conducting CMS performance evaluations according to Sec. 63.11224. For
affected boilers that burn a single type of fuel, you are exempted from
the compliance requirements of conducting a fuel analysis for each type
of fuel burned in your boiler. For purposes of this subpart, boilers
that use a supplemental fuel only for startup, unit shutdown, and
transient flame stability purposes still qualify as affected boilers
that burn a single type of fuel, and the supplemental fuel is not
subject to the fuel analysis requirements under Sec. 63.11213 and
Table 5 to this subpart.
(b) * * *
(1) For a wet scrubber, you must establish the minimum scrubber
liquid flow rate and minimum scrubber pressure drop as defined in Sec.
63.11237, as your operating limits during the three-run performance
stack test. If you use a wet scrubber and you conduct separate
performance stack tests for PM and mercury emissions, you must
establish one set of minimum scrubber liquid flow rate and pressure
drop operating limits. If you conduct multiple performance stack tests,
you must set the minimum scrubber liquid flow rate and pressure drop
operating limits at the highest minimum values established during the
performance stack tests.
(2) For an electrostatic precipitator operated with a wet scrubber,
you must establish the minimum total secondary electric power
(secondary voltage and secondary current), as defined in Sec.
63.11237, as your operating limits during the three-run performance
stack test.
* * * * *
0
11. Section 63.11212 is amended by revising paragraphs (b) and (e) to
read as follows:
Sec. 63.11212 What stack tests and procedures must I use for the
performance tests?
* * * * *
(b) You must conduct each stack test according to the requirements
in Table 4 to this subpart. Boilers that use a CEMS for carbon monoxide
(CO) are exempt from the initial CO performance testing in Table 4 to
this subpart and the oxygen concentration operating limit requirement
specified in Table 3 to this subpart.
* * * * *
(e) To determine compliance with the emission limits, you must use
the F-Factor methodology and equations in sections 12.2 and 12.3 of EPA
Method 19 of appendix A-7 to part 60 of this chapter to convert the
measured PM concentrations and the measured mercury concentrations that
result from the performance test to pounds per million Btu heat input
emission rates.
0
12. Section 63.11214 is amended by revising paragraph (c) to read as
follows:
Sec. 63.11214 How do I demonstrate initial compliance with the work
practice standard, emission reduction measures, and management
practice?
* * * * *
(c) If you own or operate an existing affected boiler with a heat
input capacity of 10 million Btu per hour or greater, you must submit a
signed certification in the Notification of Compliance Status report
that an energy assessment of the boiler and its energy use systems was
completed according to Table 2 to this subpart and is an accurate
depiction of your facility.
* * * * *
0
13. Section 63.11220 is revised to read as follows:
Sec. 63.11220 When must I conduct subsequent performance tests or
fuel analyses?
(a) If your boiler has a heat input capacity of 10 million British
thermal units per hour or greater, you must conduct all applicable
performance (stack) tests according to Sec. 63.11212 on a triennial
basis, except as specified in paragraphs (b) through (d) of this
section. Triennial performance tests must be completed no more than 37
months after the previous performance test.
(b) When demonstrating initial compliance with the PM emission
limit, if your boiler's performance test results show that your PM
emissions are equal to or less than half of the PM emission limit, you
do not need to conduct further performance tests for PM but must
continue to comply with all applicable operating limits and monitoring
requirements. If your initial performance test results show that your
PM emissions are greater than half of the PM emission limit, you must
conduct subsequent performance tests as specified in paragraph (a) of
this section.
(c) If you demonstrate compliance with the mercury emission limit
based on fuel analysis, you must conduct a fuel analysis according to
Sec. 63.11213 for each type of fuel burned as specified in paragraphs
(c)(1) and (2) of this section. If you plan to burn a new type of fuel
or fuel mixture, you must conduct a fuel analysis before burning the
new type of fuel or mixture in your boiler. You must recalculate the
mercury emission rate using Equation 1 of Sec. 63.11211. The
recalculated mercury emission rate must be less than the applicable
emission limit.
(1) When demonstrating initial compliance with the mercury emission
limit, if the mercury constituents in the fuel or fuel mixture are
measured to be equal to or less than half of the mercury emission
limit, you do not need to conduct further fuel analysis sampling but
must continue to comply with all applicable operating limits and
monitoring requirements.
(2) When demonstrating initial compliance with the mercury emission
limit, if the mercury constituents in the fuel or fuel mixture are
greater than half of the mercury emission limit, you must conduct
quarterly sampling.
(d) For existing affected boilers that have not operated since the
previous compliance demonstration and more than 3 years have passed
since the previous compliance demonstration, you must complete your
subsequent compliance demonstration no later than 180 days after the
re-start of the affected boiler.
0
14. Section 63.11221 is revised to read as follows:
Sec. 63.11221 Is there a minimum amount of monitoring data I must
obtain?
(a) You must monitor and collect data according to this section and
the site-specific monitoring plan required by Sec. 63.11205(c).
(b) You must operate the monitoring system and collect data at all
required intervals at all times the affected source is operating and
compliance is required, except for periods of monitoring system
malfunctions or out-of-control periods (see Sec. 63.8(c)(7) of this
part), repairs associated with monitoring system malfunctions or out-
of-control periods, and required monitoring system quality assurance or
quality control activities including, as applicable, calibration
checks, required zero and span
[[Page 7509]]
adjustments, and scheduled CMS maintenance as defined in your site-
specific monitoring plan. A monitoring system malfunction is any
sudden, infrequent, not reasonably preventable failure of the
monitoring system to provide valid data. Monitoring system failures
that are caused in part by poor maintenance or careless operation are
not malfunctions. You are required to complete monitoring system
repairs in response to monitoring system malfunctions or out-of-control
periods and to return the monitoring system to operation as
expeditiously as practicable.
(c) You may not use data collected during monitoring system
malfunctions or out-of-control periods, repairs associated with
monitoring system malfunctions or out-of-control periods, or required
monitoring system quality assurance or quality control activities in
calculations used to report emissions or operating levels. Any such
periods must be reported according to the requirements in Sec.
63.11225. You must use all the data collected during all other periods
in assessing the operation of the control device and associated control
system.
(d) Except for periods of monitoring system malfunctions or
monitoring system out-of-control periods, repairs associated with
monitoring system malfunctions or monitoring system out-of-control
periods, and required monitoring system quality assurance or quality
control activities (including, as applicable, calibration checks,
required zero and span adjustments, and scheduled CMS maintenance as
defined in your site-specific monitoring plan), failure to collect
required data is a deviation of the monitoring requirements.
0
15. Section 63.11223 is amended by revising paragraphs (a), (b)
introductory text, (b)(1), (b)(3) through (5), (b)(6) introductory
text, (b)(6)(i), (b)(6)(iii), (b)(7), and (c), and adding paragraphs
(d) through (g) to read as follows:
Sec. 63.11223 How do I demonstrate continuous compliance with the
work practice and management practice standards?
(a) For affected sources subject to the work practice standard or
the management practices of a tune-up, you must conduct a performance
tune-up according to paragraph (b) of this section and keep records as
required in Sec. 63.11225(c) to demonstrate continuous compliance. You
must conduct the tune-up while burning the type of fuel (or fuels in
the case of boilers that routinely burn two types of fuels at the same
time) that provided the majority of the heat input to the boiler over
the 12 months prior to the tune-up.
(b) Except as specified in paragraphs (c) through (f) of this
section, you must conduct a tune-up of the boiler biennially to
demonstrate continuous compliance as specified in paragraphs (b)(1)
through (7) of this section. Each biennial tune-up must be conducted no
more than 25 months after the previous tune-up. For a new or
reconstructed boiler, the first biennial tune-up must be no later than
25 months after the initial startup of the new or reconstructed boiler.
(1) As applicable, inspect the burner, and clean or replace any
components of the burner as necessary (you may delay the burner
inspection until the next scheduled unit shutdown, not to exceed 36
months from the previous inspection). Units that produce electricity
for sale may delay the burner inspection until the first outage, not to
exceed 36 months from the previous inspection.
* * * * *
(3) Inspect the system controlling the air-to-fuel ratio, as
applicable, and ensure that it is correctly calibrated and functioning
properly (you may delay the inspection until the next scheduled unit
shutdown, not to exceed 36 months from the previous inspection). Units
that produce electricity for sale may delay the inspection until the
first outage, not to exceed 36 months from the previous inspection.
(4) Optimize total emissions of CO. This optimization should be
consistent with the manufacturer's specifications, if available, and
with any nitrogen oxide requirement to which the unit is subject.
(5) Measure the concentrations in the effluent stream of CO in
parts per million, by volume, and oxygen in volume percent, before and
after the adjustments are made (measurements may be either on a dry or
wet basis, as long as it is the same basis before and after the
adjustments are made). Measurements may be taken using a portable CO
analyzer.
(6) Maintain on-site and submit, if requested by the Administrator,
a report containing the information in paragraphs (b)(6)(i) through
(iii) of this section.
(i) The concentrations of CO in the effluent stream in parts per
million, by volume, and oxygen in volume percent, measured at high fire
or typical operating load, before and after the tune-up of the boiler.
* * * * *
(iii) The type and amount of fuel used over the 12 months prior to
the tune-up of the boiler, but only if the unit was physically and
legally capable of using more than one type of fuel during that period.
Units sharing a fuel meter may estimate the fuel use by each unit.
(7) If the unit is not operating on the required date for a tune-
up, the tune-up must be conducted within 30 days of startup.
(c) Boilers with an oxygen trim system that maintains an optimum
air-to-fuel ratio that would otherwise be subject to a biennial tune-up
must conduct a tune-up of the boiler every 5 years as specified in
paragraphs (b)(1) through (7) of this section. Each 5-year tune-up must
be conducted no more than 61 months after the previous tune-up. For a
new or reconstructed boiler with an oxygen trim system, the first 5-
year tune-up must be no later than 61 months after the initial startup.
You may delay the burner inspection specified in paragraph (b)(1) of
this section and inspection of the system controlling the air-to-fuel
ratio specified in paragraph (b)(3) of this section until the next
scheduled unit shutdown, but you must inspect each burner and system
controlling the air-to-fuel ratio at least once every 72 months.
(d) Seasonal boilers must conduct a tune-up every 5 years as
specified in paragraphs (b)(1) through (7) of this section. Each 5-year
tune-up must be conducted no more than 61 months after the previous
tune-up. For a new or reconstructed seasonal boiler, the first 5-year
tune-up must be no later than 61 months after the initial startup. You
may delay the burner inspection specified in paragraph (b)(1) of this
section and inspection of the system controlling the air-to-fuel ratio
specified in paragraph (b)(3) of this section until the next scheduled
unit shutdown, but you must inspect each burner and system controlling
the air-to-fuel ratio at least once every 72 months. Seasonal boilers
are not subject to the emission limits in Table 1 to this subpart or
the operating limits in Table 3 to this subpart.
(e) Oil-fired boilers with a heat input capacity of equal to or
less than 5 million Btu per hour must conduct a tune-up every 5 years
as specified in paragraphs (b)(1) through (7) of this section. Each 5-
year tune-up must be conducted no more than 61 months after the
previous tune-up. For a new or reconstructed oil-fired boiler with a
heat input capacity of equal to or less than 5 million Btu per hour,
the first 5-year tune-up must be no later than 61 months after the
initial startup. You may delay the burner inspection specified in
paragraph (b)(1) of this section and inspection of the system
controlling the air-to-fuel ratio specified
[[Page 7510]]
in paragraph (b)(3) of this section until the next scheduled unit
shutdown, but you must inspect each burner and system controlling the
air-to-fuel ratio at least once every 72 months.
(f) Limited-use boilers must conduct a tune-up every 5 years as
specified in paragraphs (b)(1) through (7) of this section. Each 5-year
tune-up must be conducted no more than 61 months after the previous
tune-up. For a new or reconstructed limited-use boiler, the first 5-
year tune-up must be no later than 61 months after the initial startup.
You may delay the burner inspection specified in paragraph (b)(1) of
this section and inspection of the system controlling the air-to-fuel
ratio specified in paragraph (b)(3) of this section until the next
scheduled unit shutdown, but you must inspect each burner and system
controlling the air-to-fuel ratio at least once every 72 months.
Limited-use boilers are not subject to the emission limits in Table 1
to this subpart, the energy assessment requirements in Table 2 to this
subpart, or the operating limits in Table 3 to this subpart.
(g) If you own or operate a boiler subject to emission limits in
Table 1 of this subpart, you must minimize the boiler's startup and
shutdown periods following the manufacturer's recommended procedures,
if available. If manufacturer's recommended procedures are not
available, you must follow recommended procedures for a unit of similar
design for which manufacturer's recommended procedures are available.
You must submit a signed statement in the Notification of Compliance
Status report that indicates that you conducted startups and shutdowns
according to the manufacturer's recommended procedures or procedures
specified for a boiler of similar design if manufacturer's recommended
procedures are not available.
0
16. Section 63.11224 is amended by:
0
a. Revising paragraphs (a) introductory text, (a)(1) through (3),
(a)(5), (a)(6),
0
b. Adding paragraph (a)(7).
0
c. Revising paragraphs (c)(1) introductory text, (c)(2) introductory
text, and (d).
0
d. Revising paragraphs (e) introductory text, (e)(6), and (e)(7).
0
e. Adding paragraph (e)(8).
0
f. Revising paragraph (f)(7).
The revisions and additions read as follows:
Sec. 63.11224 What are my monitoring, installation, operation, and
maintenance requirements?
(a) If your boiler is subject to a CO emission limit in Table 1 to
this subpart, you must either install, operate, and maintain a CEMS for
CO and oxygen according to the procedures in paragraphs (a)(1) through
(6) of this section, or install, calibrate, operate, and maintain an
oxygen analyzer system, as defined in Sec. 63.11237, according to the
manufacturer's recommendations and paragraphs (a)(7) and (d) of this
section, as applicable, by the compliance date specified in Sec.
63.11196. Where a certified CO CEMS is used, the CO level shall be
monitored at the outlet of the boiler, after any add-on controls or
flue gas recirculation system and before release to the atmosphere.
Boilers that use a CO CEMS are exempt from the initial CO performance
testing and oxygen concentration operating limit requirements specified
in Sec. 63.11211(a) of this subpart. Oxygen monitors and oxygen trim
systems must be installed to monitor oxygen in the boiler flue gas,
boiler firebox, or other appropriate intermediate location.
(1) Each CO CEMS must be installed, operated, and maintained
according to the applicable procedures under Performance Specification
4, 4A, or 4B at 40 CFR part 60, appendix B, and each oxygen CEMS must
be installed, operated, and maintained according to Performance
Specification 3 at 40 CFR part 60, appendix B. Both the CO and oxygen
CEMS must also be installed, operated, and maintained according to the
site-specific monitoring plan developed according to paragraph (c) of
this section.
(2) You must conduct a performance evaluation of each CEMS
according to the requirements in Sec. 63.8(e) and according to
Performance Specifications 3 and 4, 4A, or 4B at 40 CFR part 60,
appendix B.
(3) Each CEMS must complete a minimum of one cycle of operation
(sampling, analyzing, and data recording) every 15 minutes. You must
have CEMS data values from a minimum of four successive cycles of
operation representing each of the four 15-minute periods in an hour,
or at least two 15-minute data values during an hour when CEMS
calibration, quality assurance, or maintenance activities are being
performed, to have a valid hour of data.
* * * * *
(5) You must calculate hourly averages, corrected to 3 percent
oxygen, from each hour of CO CEMS data in parts per million CO
concentrations and determine the 10-day rolling average of all recorded
readings, except as provided in Sec. 63.11221(c). Calculate a 10-day
rolling average from all of the hourly averages collected for the 10-
day operating period using Equation 2 of this section.
[GRAPHIC] [TIFF OMITTED] TR01FE13.000
Where:
Hpvi = the hourly parameter value for hour i
n = the number of valid hourly parameter values collected over 10
boiler operating days
(6) For purposes of collecting CO data, you must operate the CO
CEMS as specified in Sec. 63.11221(b). For purposes of calculating
data averages, you must use all the data collected during all periods
in assessing compliance, except that you must exclude certain data as
specified in Sec. 63.11221(c). Periods when CO data are unavailable
may constitute monitoring deviations as specified in Sec. 63.11221(d).
(7) You must operate the oxygen analyzer system at or above the
minimum oxygen level that is established as the operating limit
according to Table 6 to this subpart when firing the fuel or fuel
mixture utilized during the most recent CO performance stack test.
Operation of oxygen trim systems to meet these requirements shall not
be done in a manner which compromises furnace safety.
* * * * *
(c) * * *
(1) For each CMS required in this section, you must develop, and
submit to the EPA Administrator for approval upon request, a site-
specific monitoring plan that addresses paragraphs (c)(1)(i) through
(iii) of this section. You must submit this site-specific monitoring
plan (if requested) at least 60 days before your initial performance
evaluation of your CMS.
* * * * *
[[Page 7511]]
(2) In your site-specific monitoring plan, you must also address
paragraphs (c)(2)(i) through (iii) of this section.
* * * * *
(d) If you have an operating limit that requires the use of a CMS,
you must install, operate, and maintain each CPMS according to the
procedures in paragraphs (d)(1) through (4) of this section.
(1) The CPMS must complete a minimum of one cycle of operation
every 15 minutes. You must have data values from a minimum of four
successive cycles of operation representing each of the four 15-minute
periods in an hour, or at least two 15-minute data values during an
hour when CMS calibration, quality assurance, or maintenance activities
are being performed, to have a valid hour of data.
(2) You must calculate hourly arithmetic averages from each hour of
CPMS data in units of the operating limit and determine the 30-day
rolling average of all recorded readings, except as provided in Sec.
63.11221(c). Calculate a 30-day rolling average from all of the hourly
averages collected for the 30-day operating period using Equation 3 of
this section.
[GRAPHIC] [TIFF OMITTED] TR01FE13.001
Where:
Hpvi = the hourly parameter value for hour i
n = the number of valid hourly parameter values collected over 30
boiler operating days
(3) For purposes of collecting data, you must operate the CPMS as
specified in Sec. 63.11221(b). For purposes of calculating data
averages, you must use all the data collected during all periods in
assessing compliance, except that you must exclude certain data as
specified in Sec. 63.11221(c). Periods when CPMS data are unavailable
may constitute monitoring deviations as specified in Sec. 63.11221(d).
(4) Record the results of each inspection, calibration, and
validation check.
(e) If you have an applicable opacity operating limit under this
rule, you must install, operate, certify and maintain each COMS
according to the procedures in paragraphs (e)(1) through (8) of this
section by the compliance date specified in Sec. 63.11196.
* * * * *
(6) You must operate and maintain each COMS according to the
requirements in the monitoring plan and the requirements of Sec.
63.8(e). You must identify periods the COMS is out of control including
any periods that the COMS fails to pass a daily calibration drift
assessment, a quarterly performance audit, or an annual zero alignment
audit.
(7) You must calculate and record 6-minute averages from the
opacity monitoring data and determine and record the daily block
average of recorded readings, except as provided in Sec. 63.11221(c).
(8) For purposes of collecting opacity data, you must operate the
COMS as specified in Sec. 63.11221(b). For purposes of calculating
data averages, you must use all the data collected during all periods
in assessing compliance, except that you must exclude certain data as
specified in Sec. 63.11221(c). Periods when COMS data are unavailable
may constitute monitoring deviations as specified in Sec. 63.11221(d).
(f) * * *
(7) For positive pressure fabric filter systems that do not duct
all compartments or cells to a common stack, a bag leak detection
system must be installed in each baghouse compartment or cell.
* * * * *
0
17. Section 63.11225 is amended by:
0
a. Revising paragraphs (a) introductory text, (a)(1), (a)(2), (a)(4),
(a)(5), (b) introductory text, (b)(2), (c) introductory text, (c)(2)
introductory text, and (c)(2)(ii).
0
b. Adding paragraphs (c)(2)(iii) through (vi).
0
c. Revising paragraphs (d), (e), and (g).
The revisions and additions read as follows:
Sec. 63.11225 What are my notification, reporting, and recordkeeping,
requirements?
(a) You must submit the notifications specified in paragraphs
(a)(1) through (5) of this section to the administrator.
(1) You must submit all of the notifications in Sec. Sec. 63.7(b);
63.8(e) and (f); and 63.9(b) through (e), (g), and (h) that apply to
you by the dates specified in those sections except as specified in
paragraphs (a)(2) and (4) of this section.
(2) An Initial Notification must be submitted no later than January
20, 2014 or within 120 days after the source becomes subject to the
standard.
* * * * *
(4) You must submit the Notification of Compliance Status no later
than 120 days after the applicable compliance date specified in Sec.
63.11196 unless you must conduct a performance stack test. If you must
conduct a performance stack test, you must submit the Notification of
Compliance Status within 60 days of completing the performance stack
test. You must submit the Notification of Compliance Status in
accordance with paragraphs (a)(4)(i) and (vi) of this section. The
Notification of Compliance Status must include the information and
certification(s) of compliance in paragraphs (a)(4)(i) through (v) of
this section, as applicable, and signed by a responsible official.
(i) You must submit the information required in Sec. 63.9(h)(2),
except the information listed in Sec. 63.9(h)(2)(i)(B), (D), (E), and
(F). If you conduct any performance tests or CMS performance
evaluations, you must submit that data as specified in paragraph (e) of
this section. If you conduct any opacity or visible emission
observations, or other monitoring procedures or methods, you must
submit that data to the Administrator at the appropriate address listed
in Sec. 63.13.
(ii) ``This facility complies with the requirements in Sec.
63.11214 to conduct an initial tune-up of the boiler.''
(iii) ``This facility has had an energy assessment performed
according to Sec. 63.11214(c).''
(iv) For units that install bag leak detection systems: ``This
facility complies with the requirements in Sec. 63.11224(f).''
(v) For units that do not qualify for a statutory exemption as
provided in section 129(g)(1) of the Clean Air Act: ``No secondary
materials that are solid waste were combusted in any affected unit.''
(vi) The notification must be submitted electronically using the
Compliance and Emissions Data Reporting Interface (CEDRI) that is
accessed through EPA's Central Data Exchange (CDX) (www.epa.gov/cdx).
However, if the reporting form specific to this subpart is not
available in CEDRI at the time that the report is due, the written
Notification of Compliance Status must be submitted to the
[[Page 7512]]
Administrator at the appropriate address listed in Sec. 63.13.
(5) If you are using data from a previously conducted emission test
to serve as documentation of conformance with the emission standards
and operating limits of this subpart, you must include in the
Notification of Compliance Status the date of the test and a summary of
the results, not a complete test report, relative to this subpart.
(b) You must prepare, by March 1 of each year, and submit to the
delegated authority upon request, an annual compliance certification
report for the previous calendar year containing the information
specified in paragraphs (b)(1) through (4) of this section. You must
submit the report by March 15 if you had any instance described by
paragraph (b)(3) of this section. For boilers that are subject only to
a requirement to conduct a biennial or 5-year tune-up according to
Sec. 63.11223(a) and not subject to emission limits or operating
limits, you may prepare only a biennial or 5-year compliance report as
specified in paragraphs (b)(1) and (2) of this section.
* * * * *
(2) Statement by a responsible official, with the official's name,
title, phone number, email address, and signature, certifying the
truth, accuracy and completeness of the notification and a statement of
whether the source has complied with all the relevant standards and
other requirements of this subpart. Your notification must include the
following certification(s) of compliance, as applicable, and signed by
a responsible official:
(i) ``This facility complies with the requirements in Sec.
63.11223 to conduct a biennial or 5-year tune-up, as applicable, of
each boiler.''
(ii) For units that do not qualify for a statutory exemption as
provided in section 129(g)(1) of the Clean Air Act: ``No secondary
materials that are solid waste were combusted in any affected unit.''
(iii) ``This facility complies with the requirement in Sec. Sec.
63.11214(d) and 63.11223(g) to minimize the boiler's time spent during
startup and shutdown and to conduct startups and shutdowns according to
the manufacturer's recommended procedures or procedures specified for a
boiler of similar design if manufacturer's recommended procedures are
not available.''
* * * * *
(c) You must maintain the records specified in paragraphs (c)(1)
through (7) of this section.
* * * * *
(2) You must keep records to document conformance with the work
practices, emission reduction measures, and management practices
required by Sec. 63.11214 and Sec. 63.11223 as specified in
paragraphs (c)(2)(i) through (vi) of this section.
* * * * *
(ii) For operating units that combust non-hazardous secondary
materials that have been determined not to be solid waste pursuant to
Sec. 241.3(b)(1) of this chapter, you must keep a record which
documents how the secondary material meets each of the legitimacy
criteria under Sec. 241.3(d)(1). If you combust a fuel that has been
processed from a discarded non-hazardous secondary material pursuant to
Sec. 241.3(b)(4) of this chapter, you must keep records as to how the
operations that produced the fuel satisfies the definition of
processing in Sec. 241.2 and each of the legitimacy criteria in Sec.
241.3(d)(1) of this chapter. If the fuel received a non-waste
determination pursuant to the petition process submitted under Sec.
241.3(c) of this chapter, you must keep a record that documents how the
fuel satisfies the requirements of the petition process. For operating
units that combust non-hazardous secondary materials as fuel per Sec.
241.4, you must keep records documenting that the material is a listed
non-waste under Sec. 241.4(a).
(iii) For each boiler required to conduct an energy assessment, you
must keep a copy of the energy assessment report.
(iv) For each boiler subject to an emission limit in Table 1 to
this subpart, you must also keep records of monthly fuel use by each
boiler, including the type(s) of fuel and amount(s) used.
(v) For each boiler that meets the definition of seasonal boiler,
you must keep records of days of operation per year.
(vi) For each boiler that meets the definition of limited-use
boiler, you must keep a copy of the federally enforceable permit that
limits the annual capacity factor to less than or equal to 10 percent
and records of fuel use for the days the boiler is operating.
* * * * *
(d) Your records must be in a form suitable and readily available
for expeditious review. You must keep each record for 5 years following
the date of each recorded action. You must keep each record on-site or
be accessible from a central location by computer or other means that
instantly provide access at the site for at least 2 years after the
date of each recorded action. You may keep the records off site for the
remaining 3 years.
(e)(1) Within 60 days after the date of completing each performance
test (defined in Sec. 63.2) as required by this subpart you must
submit the results of the performance tests, including any associated
fuel analyses, required by this subpart to EPA's WebFIRE database by
using CEDRI that is accessed through EPA's CDX (www.epa.gov/cdx).
Performance test data must be submitted in the file format generated
through use of EPA's Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/index.html). Only data collected using test
methods on the ERT Web site are subject to this requirement for
submitting reports electronically to WebFIRE. Owners or operators who
claim that some of the information being submitted for performance
tests is confidential business information (CBI) must submit a complete
ERT file including information claimed to be CBI on a compact disk or
other commonly used electronic storage media (including, but not
limited to, flash drives) to EPA. The electronic media must be clearly
marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention:
WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703.
The same ERT file with the CBI omitted must be submitted to EPA via CDX
as described earlier in this paragraph. At the discretion of the
delegated authority, you must also submit these reports, including CBI,
to the delegated authority in the format specified by the delegated
authority. For any performance test conducted using test methods that
are not listed on the ERT Web site, the owner or operator shall submit
the results of the performance test in paper submissions to the
Administrator at the appropriate address listed in Sec. 63.13.
(2) Within 60 days after the date of completing each CEMS
performance evaluation test as defined in Sec. 63.2, you must submit
relative accuracy test audit (RATA) data to EPA's CDX by using CEDRI in
accordance with paragraph (e)(1) of this section. Only RATA pollutants
that can be documented with the ERT (as listed on the ERT Web site) are
subject to this requirement. For any performance evaluations with no
corresponding RATA pollutants listed on the ERT Web site, the owner or
operator shall submit the results of the performance evaluation in
paper submissions to the Administrator at the appropriate address
listed in Sec. 63.13.
* * * * *
(g) If you have switched fuels or made a physical change to the
boiler and the fuel switch or change resulted in the
[[Page 7513]]
applicability of a different subcategory within subpart JJJJJJ, in the
boiler becoming subject to subpart JJJJJJ, or in the boiler switching
out of subpart JJJJJJ due to a change to 100 percent natural gas, or
you have taken a permit limit that resulted in you being subject to
subpart JJJJJJ, you must provide notice of the date upon which you
switched fuels, made the physical change, or took a permit limit within
30 days of the change. The notification must identify:
(1) The name of the owner or operator of the affected source, the
location of the source, the boiler(s) that have switched fuels, were
physically changed, or took a permit limit, and the date of the notice.
(2) The date upon which the fuel switch, physical change, or permit
limit occurred.
18. Section 63.11226 is revised to read as follows:
Sec. 63.11226 Affirmative defense for violation of emission standards
during malfunction.
In response to an action to enforce the standards set forth in
Sec. 63.11201 you may assert an affirmative defense to a claim for
civil penalties for violations of such standards that are caused by
malfunction, as defined at 40 CFR 63.2. Appropriate penalties may be
assessed if you fail to meet your burden of proving all of the
requirements in the affirmative defense. The affirmative defense shall
not be available for claims for injunctive relief.
(a) Assertion of affirmative defense. To establish the affirmative
defense in any action to enforce such a standard, you must timely meet
the reporting requirements in paragraph (b) of this section, and must
prove by a preponderance of evidence that:
(1) The violation:
(i) Was caused by a sudden, infrequent, and unavoidable failure of
air pollution control equipment, process equipment, or a process to
operate in a normal or usual manner; and
(ii) Could not have been prevented through careful planning, proper
design or better operation and maintenance practices; and
(iii) Did not stem from any activity or event that could have been
foreseen and avoided, or planned for; and
(iv) Was not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
(2) Repairs were made as expeditiously as possible when a violation
occurred; and
(3) The frequency, amount, and duration of the violation (including
any bypass) were minimized to the maximum extent practicable; and
(4) If the violation resulted from a bypass of control equipment or
a process, then the bypass was unavoidable to prevent loss of life,
personal injury, or severe property damage; and
(5) All possible steps were taken to minimize the impact of the
violation on ambient air quality, the environment, and human health;
and
(6) All emissions monitoring and control systems were kept in
operation if at all possible, consistent with safety and good air
pollution control practices; and
(7) All of the actions in response to the violation were documented
by properly signed, contemporaneous operating logs; and
(8) At all times, the affected source was operated in a manner
consistent with good practices for minimizing emissions; and
(9) A written root cause analysis has been prepared, the purpose of
which is to determine, correct, and eliminate the primary causes of the
malfunction and the violation resulting from the malfunction event at
issue. The analysis shall also specify, using best monitoring methods
and engineering judgment, the amount of any emissions that were the
result of the malfunction.
(b) Report. The owner or operator seeking to assert an affirmative
defense shall submit a written report to the Administrator with all
necessary supporting documentation, that it has met the requirements
set forth in paragraph (a) of this section. This affirmative defense
report shall be included in the first periodic compliance, deviation
report or excess emission report otherwise required after the initial
occurrence of the violation of the relevant standard (which may be the
end of any applicable averaging period). If such compliance, deviation
report or excess emission report is due less than 45 days after the
initial occurrence of the violation, the affirmative defense report may
be included in the second compliance, deviation report or excess
emission report due after the initial occurrence of the violation of
the relevant standard.
0
19. Section 63.11236 is amended by revising paragraph (a) to read as
follows:
Sec. 63.11236 Who implements and enforces this subpart?
(a) This subpart can be implemented and enforced by EPA or an
administrator such as your state, local, or tribal agency. If the EPA
Administrator has delegated authority to your state, local, or tribal
agency, then that agency has the authority to implement and enforce
this subpart. You should contact your EPA Regional Office to find out
if implementation and enforcement of this subpart is delegated to your
state, local, or tribal agency.
* * * * *
0
20. Section 63.11237 is amended as follows:
0
a. By adding definitions in alphabetical order for ``10-day rolling
average,'' ``30-day rolling average,'' ``Annual heat input,''
``Biodiesel,'' ``Calendar year,'' ``Common stack,'' ``Daily block
average,'' ``Distillate oil,'' ``Electric boiler,'' ``Electric utility
steam generating unit (EGU),'' ``Energy management program,''
``Fluidized bed boiler,'' ``Fluidized bed combustion,'' ``Hourly
average,'' ``Limited-use boiler,'' ``Load fraction,'' ``Minimum
scrubber pressure drop,'' ``Minimum sorbent injection rate,'' ``Minimum
total secondary electric power,'' ``Operating day,'' ``Oxygen analyzer
system,'' ``Oxygen trim system,'' ``Process heater,'' ``Regulated gas
stream,'' ``Residential boiler,'' ``Residual oil,'' ``Seasonal
boiler,'' ``Shutdown,'' ``Solid fuel,'' ``Startup,'' ``Temporary
boiler,'' ``Tune-up,'' ``Vegetable oil,'' ``Voluntary Consensus
Standards (VCS),'' and ``Wet scrubber.''
0
b. By revising the definitions for ``Bag leak detection system,''
``Biomass subcategory,'' ``Boiler,'' ``Boiler system,'' ``Deviation,''
``Dry scrubber,'' ``Electrostatic precipitator (ESP),'' ``Energy
assessment,'' ``Energy use system,'' ``Federally enforceable,'' ``Gas-
fired boiler,'' ``Heat input,'' ``Hot water heater,'' ``Institutional
boiler,'' ``Liquid fuel,'' ``Minimum activated carbon injection rate,''
``Minimum oxygen level,'' ``Minimum scrubber liquid flow rate,''
``Natural gas,'' ``Oil subcategory,'' ``Particulate matter,'' ``Period
of gas curtailment or supply interruption,'' ``Qualified Energy
Assessor,'' ``Solid fossil fuel,'' and ``Waste heat boiler.''
0
c. By removing the definitions for ``Annual heat input basis,''
``Minimum PM scrubber pressure drop,'' ``Minimum sorbent flow rate,''
and ``Minimum voltage or amperage''.
Sec. 63.11237 What definitions apply to this subpart?
10-day rolling average means the arithmetic mean of all valid hours
of data from 10 successive operating days, except for periods of
startup and shutdown and periods when the unit is not operating.
30-day rolling average means the arithmetic mean of all valid hours
of data from 30 successive operating days, except for periods of
startup and shutdown and periods when the unit is not operating.
* * * * *
[[Page 7514]]
Annual heat input means the heat input for the 12 months preceding
the compliance demonstration.
Bag leak detection system means a group of instruments that are
capable of monitoring particulate matter loadings in the exhaust of a
fabric filter (i.e., baghouse) in order to detect bag failures. A bag
leak detection system includes, but is not limited to, an instrument
that operates on electrodynamic, triboelectric, light scattering, light
transmittance, or other principle to monitor relative particulate
matter loadings.
Biodiesel means a mono-alkyl ester derived from biomass and
conforming to ASTM D6751-11b, Standard Specification for Biodiesel Fuel
Blend Stock (B100) for Middle Distillate Fuels (incorporated by
reference, see Sec. 63.14).
* * * * *
Biomass subcategory includes any boiler that burns any biomass and
is not in the coal subcategory.
Boiler means an enclosed device using controlled flame combustion
in which water is heated to recover thermal energy in the form of steam
and/or hot water. Controlled flame combustion refers to a steady-state,
or near steady-state, process wherein fuel and/or oxidizer feed rates
are controlled. A device combusting solid waste, as defined in Sec.
241.3 of this chapter, is not a boiler unless the device is exempt from
the definition of a solid waste incineration unit as provided in
section 129(g)(1) of the Clean Air Act. Waste heat boilers, process
heaters, and autoclaves are excluded from the definition of Boiler.
Boiler system means the boiler and associated components, such as,
feedwater systems, combustion air systems, fuel systems (including
burners), blowdown systems, combustion control systems, steam systems,
and condensate return systems, directly connected to and serving the
energy use systems.
Calendar year means the period between January 1 and December 31,
inclusive, for a given year.
* * * * *
Common stack means the exhaust of emissions from two or more
affected units through a single flue. Affected units with a common
stack may each have separate air pollution control systems located
before the common stack, or may have a single air pollution control
system located after the exhausts come together in a single flue.
Daily block average means the arithmetic mean of all valid emission
concentrations or parameter levels recorded when a unit is operating
measured over the 24-hour period from 12 a.m. (midnight) to 12 a.m.
(midnight), except for periods of startup and shutdown and periods when
the unit is not operating.
Deviation (1) Means any instance in which an affected source
subject to this subpart, or an owner or operator of such a source:
(i) Fails to meet any applicable requirement or obligation
established by this subpart including, but not limited to, any emission
limit, operating limit, or work practice standard; or
(ii) Fails to meet any term or condition that is adopted to
implement an applicable requirement in this subpart and that is
included in the operating permit for any affected source required to
obtain such a permit.
(2) A deviation is not always a violation.
Distillate oil means fuel oils that contain 0.05 weight percent
nitrogen or less and comply with the specifications for fuel oil
numbers 1 and 2, as defined by the American Society of Testing and
Materials in ASTM D396 (incorporated by reference, see Sec. 63.14) or
diesel fuel oil numbers 1 and 2, as defined by the American Society for
Testing and Materials in ASTM D975 (incorporated by reference, see
Sec. 63.14), kerosene, and biodiesel as defined by the American
Society of Testing and Materials in ASTM D6751-11b (incorporated by
reference, see Sec. 63.14).
Dry scrubber means an add-on air pollution control system that
injects dry alkaline sorbent (dry injection) or sprays an alkaline
sorbent (spray dryer) to react with and neutralize acid gas in the
exhaust stream forming a dry powder material. Sorbent injection systems
used as control devices in fluidized bed boilers and process heaters
are included in this definition. A dry scrubber is a dry control
system.
Electric boiler means a boiler in which electric heating serves as
the source of heat. Electric boilers that burn gaseous or liquid fuel
during periods of electrical power curtailment or failure are included
in this definition.
Electric utility steam generating unit (EGU) means a fossil fuel-
fired combustion unit of more than 25 megawatts that serves a generator
that produces electricity for sale. A fossil fuel-fired unit that
cogenerates steam and electricity and supplies more than one-third of
its potential electric output capacity and more than 25 megawatts
electrical output to any utility power distribution system for sale is
considered an electric utility steam generating unit. To be ``capable
of combusting'' fossil fuels, an EGU would need to have these fuels
allowed in their operating permits and have the appropriate fuel
handling facilities on-site or otherwise available (e.g., coal handling
equipment, including coal storage area, belts and conveyers,
pulverizers, etc.; oil storage facilities). In addition, fossil fuel-
fired EGU means any EGU that fired fossil fuel for more than 10.0
percent of the average annual heat input in any 3 consecutive calendar
years or for more than 15.0 percent of the annual heat input during any
one calendar year after April 16, 2015.
Electrostatic precipitator (ESP) means an add-on air pollution
control device used to capture particulate matter by charging the
particles using an electrostatic field, collecting the particles using
a grounded collecting surface, and transporting the particles into a
hopper. An electrostatic precipitator is usually a dry control system.
Energy assessment means the following for the emission units
covered by this subpart:
(1) The energy assessment for facilities with affected boilers with
less than 0.3 trillion Btu per year (TBtu/year) heat input capacity
will be 8 on-site technical labor hours in length maximum, but may be
longer at the discretion of the owner or operator of the affected
source. The boiler system(s) and any on-site energy use system(s)
accounting for at least 50 percent of the affected boiler(s) energy
(e.g., steam, hot water, or electricity) production, as applicable,
will be evaluated to identify energy savings opportunities, within the
limit of performing an 8-hour energy assessment.
(2) The energy assessment for facilities with affected boilers with
0.3 to 1.0 TBtu/year heat input capacity will be 24 on-site technical
labor hours in length maximum, but may be longer at the discretion of
the owner or operator of the affected source. The boiler system(s) and
any on-site energy use system(s) accounting for at least 33 percent of
the affected boiler(s) energy (e.g., steam, hot water, or electricity)
production, as applicable, will be evaluated to identify energy savings
opportunities, within the limit of performing a 24-hour energy
assessment.
(3) The energy assessment for facilities with affected boilers with
greater than 1.0 TBtu/year heat input capacity will be up to 24 on-site
technical labor hours in length for the first TBtu/year plus 8 on-site
technical labor hours for every additional 1.0 TBtu/year not to exceed
160 on-site technical hours, but may be longer at the discretion of the
owner or operator of the affected source. The boiler
[[Page 7515]]
system(s) and any on-site energy use system(s) accounting for at least
20 percent of the affected boiler(s) energy (e.g., steam, hot water, or
electricity) production, as applicable, will be evaluated to identify
energy savings opportunities.
(4) The on-site energy use system(s) serving as the basis for the
percent of affected boiler(s) energy production, as applicable, in
paragraphs (1), (2), and (3) of this definition may be segmented by
production area or energy use area as most logical and applicable to
the specific facility being assessed (e.g., product X manufacturing
area; product Y drying area; Building Z).
Energy management program means a program that includes a set of
practices and procedures designed to manage energy use that are
demonstrated by the facility's energy policies, a facility energy
manager and other staffing responsibilities, energy performance
measurement and tracking methods, an energy saving goal, action plans,
operating procedures, internal reporting requirements, and periodic
review intervals used at the facility. Facilities may establish their
program through energy management systems compatible with ISO 50001.
Energy use system (1) Includes the following systems located on the
site of the affected boiler that use energy provided by the boiler:
(i) Process heating; compressed air systems; machine drive (motors,
pumps, fans); process cooling; facility heating, ventilation, and air
conditioning systems; hot water systems; building envelop; and
lighting; or
(ii) Other systems that use steam, hot water, process heat, or
electricity, provided by the affected boiler.
(2) Energy use systems are only those systems using energy clearly
produced by affected boilers.
* * * * *
Federally enforceable means all limitations and conditions that are
enforceable by the EPA Administrator, including, but not limited to,
the requirements of 40 CFR parts 60, 61, 63, and 65, requirements
within any applicable state implementation plan, and any permit
requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and
40 CFR 51.24.
Fluidized bed boiler means a boiler utilizing a fluidized bed
combustion process that is not a pulverized coal boiler.
Fluidized bed combustion means a process where a fuel is burned in
a bed of granulated particles, which are maintained in a mobile
suspension by the forward flow of air and combustion products.
* * * * *
Gas-fired boiler includes any boiler that burns gaseous fuels not
combined with any solid fuels and burns liquid fuel only during periods
of gas curtailment, gas supply interruption, startups, or periodic
testing on liquid fuel. Periodic testing of liquid fuel shall not
exceed a combined total of 48 hours during any calendar year.
Heat input means heat derived from combustion of fuel in a boiler
and does not include the heat input from preheated combustion air,
recirculated flue gases, returned condensate, or exhaust gases from
other sources such as gas turbines, internal combustion engines, kilns.
Hot water heater means a closed vessel with a capacity of no more
than 120 U.S. gallons in which water is heated by combustion of
gaseous, liquid, or biomass fuel and hot water is withdrawn for use
external to the vessel. Hot water boilers (i.e., not generating steam)
combusting gaseous, liquid, or biomass fuel with a heat input capacity
of less than 1.6 million Btu per hour are included in this definition.
The 120 U.S. gallon capacity threshold to be considered a hot water
heater is independent of the 1.6 million Btu per hour heat input
capacity threshold for hot water boilers. Hot water heater also means a
tankless unit that provides on-demand hot water.
Hourly average means the arithmetic average of at least four CMS
data values representing the four 15-minute periods in an hour, or at
least two 15-minute data values during an hour when CMS calibration,
quality assurance, or maintenance activities are being performed.
* * * * *
Institutional boiler means a boiler used in institutional
establishments such as, but not limited to, medical centers, nursing
homes, research centers, institutions of higher education, elementary
and secondary schools, libraries, religious establishments, and
governmental buildings to provide electricity, steam, and/or hot water.
Limited-use boiler means any boiler that burns any amount of solid
or liquid fuels and has a federally enforceable average annual capacity
factor of no more than 10 percent.
Liquid fuel includes, but is not limited to, distillate oil,
residual oil, any form of liquid fuel derived from petroleum, used oil
meeting the specification in 40 CFR 279.11, liquid biofuels, biodiesel,
and vegetable oil, and comparable fuels as defined under 40 CFR 261.38.
Load fraction means the actual heat input of a boiler divided by
heat input during the performance test that established the minimum
sorbent injection rate or minimum activated carbon injection rate,
expressed as a fraction (e.g., for 50 percent load the load fraction is
0.5).
Minimum activated carbon injection rate means load fraction
multiplied by the lowest hourly average activated carbon injection rate
measured according to Table 6 to this subpart during the most recent
performance stack test demonstrating compliance with the applicable
emission limit.
Minimum oxygen level means the lowest hourly average oxygen level
measured according to Table 6 to this subpart during the most recent
performance stack test demonstrating compliance with the applicable
carbon monoxide emission limit.
Minimum scrubber liquid flow rate means the lowest hourly average
scrubber liquid flow rate (e.g., to the particulate matter scrubber)
measured according to Table 6 to this subpart during the most recent
performance stack test demonstrating compliance with the applicable
emission limit.
Minimum scrubber pressure drop means the lowest hourly average
scrubber pressure drop measured according to Table 6 to this subpart
during the most recent performance stack test demonstrating compliance
with the applicable emission limit.
Minimum sorbent injection rate means:
(1) The load fraction multiplied by the lowest hourly average
sorbent injection rate for each sorbent measured according to Table 6
to this subpart during the most recent performance stack test
demonstrating compliance with the applicable emission limits; or
(2) For fluidized bed combustion, the lowest average ratio of
sorbent to sulfur measured during the most recent performance test.
Minimum total secondary electric power means the lowest hourly
average total secondary electric power determined from the values of
secondary voltage and secondary current to the electrostatic
precipitator measured according to Table 6 to this subpart during the
most recent performance stack test demonstrating compliance with the
applicable emission limits.
Natural gas means:
(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon
gases found in geologic formations beneath
[[Page 7516]]
the earth's surface, of which the principal constituent is methane; or
(2) Liquefied petroleum gas, as defined by the American Society for
Testing and Materials in ASTM D1835 (incorporated by reference, see
Sec. 63.14); or
(3) A mixture of hydrocarbons that maintains a gaseous state at ISO
conditions (i.e., a temperature of 288 Kelvin, a relative humidity of
60 percent, and a pressure of 101.3 kilopascals). Additionally, natural
gas must either be composed of at least 70 percent methane by volume or
have a gross calorific value between 35 and 41 megajoules (MJ) per dry
standard cubic meter (950 and 1,100 Btu per dry standard cubic foot);
or
(4) Propane or propane-derived synthetic natural gas. Propane means
a colorless gas derived from petroleum and natural gas, with the
molecular structure C3H8.
Oil subcategory includes any boiler that burns any liquid fuel and
is not in either the biomass or coal subcategories. Gas-fired boilers
that burn liquid fuel only during periods of gas curtailment, gas
supply interruptions, startups, or for periodic testing are not
included in this definition. Periodic testing on liquid fuel shall not
exceed a combined total of 48 hours during any calendar year.
* * * * *
Operating day means a 24-hour period between 12 midnight and the
following midnight during which any fuel is combusted at any time in
the boiler unit. It is not necessary for fuel to be combusted for the
entire 24-hour period.
Oxygen analyzer system means all equipment required to determine
the oxygen content of a gas stream and used to monitor oxygen in the
boiler flue gas, boiler firebox, or other appropriate intermediate
location. This definition includes oxygen trim systems.
Oxygen trim system means a system of monitors that is used to
maintain excess air at the desired level in a combustion device. A
typical system consists of a flue gas oxygen and/or carbon monoxide
monitor that automatically provides a feedback signal to the combustion
air controller.
Particulate matter (PM) means any finely divided solid or liquid
material, other than uncombined water, as measured by the test methods
specified under this subpart, or an approved alternative method.
* * * * *
Period of gas curtailment or supply interruption means a period of
time during which the supply of gaseous fuel to an affected boiler is
restricted or halted for reasons beyond the control of the facility.
The act of entering into a contractual agreement with a supplier of
natural gas established for curtailment purposes does not constitute a
reason that is under the control of a facility for the purposes of this
definition. An increase in the cost or unit price of natural gas due to
normal market fluctuations not during periods of supplier delivery
restriction does not constitute a period of natural gas curtailment or
supply interruption. On-site gaseous fuel system emergencies or
equipment failures qualify as periods of supply interruption when the
emergency or failure is beyond the control of the facility.
Process heater means an enclosed device using controlled flame, and
the unit's primary purpose is to transfer heat indirectly to a process
material (liquid, gas, or solid) or to a heat transfer material (e.g.,
glycol or a mixture of glycol and water) for use in a process unit,
instead of generating steam. Process heaters are devices in which the
combustion gases do not come into direct contact with process
materials. Process heaters include units that heat water/water mixtures
for pool heating, sidewalk heating, cooling tower water heating, power
washing, or oil heating.
Qualified energy assessor means:
(1) Someone who has demonstrated capabilities to evaluate energy
savings opportunities for steam generation and major energy using
systems, including, but not limited to:
(i) Boiler combustion management.
(ii) Boiler thermal energy recovery, including
(A) Conventional feed water economizer,
(B) Conventional combustion air preheater, and
(C) Condensing economizer.
(iii) Boiler blowdown thermal energy recovery.
(iv) Primary energy resource selection, including
(A) Fuel (primary energy source) switching, and
(B) Applied steam energy versus direct-fired energy versus
electricity.
(v) Insulation issues.
(vi) Steam trap and steam leak management.
(vii) Condensate recovery.
(viii) Steam end-use management.
(2) Capabilities and knowledge includes, but is not limited to:
(i) Background, experience, and recognized abilities to perform the
assessment activities, data analysis, and report preparation.
(ii) Familiarity with operating and maintenance practices for steam
or process heating systems.
(iii) Additional potential steam system improvement opportunities
including improving steam turbine operations and reducing steam demand.
(iv) Additional process heating system opportunities including
effective utilization of waste heat and use of proper process heating
methods.
(v) Boiler-steam turbine cogeneration systems.
(vi) Industry specific steam end-use systems.
Regulated gas stream means an offgas stream that is routed to a
boiler for the purpose of achieving compliance with a standard under
another subpart of this part or part 60, part 61, or part 65 of this
chapter.
Residential boiler means a boiler used to provide heat and/or hot
water and/or as part of a residential combined heat and power system.
This definition includes boilers located at an institutional facility
(e.g., university campus, military base, church grounds) or commercial/
industrial facility (e.g., farm) used primarily to provide heat and/or
hot water for:
(1) A dwelling containing four or fewer families, or
(2) A single unit residence dwelling that has since been converted
or subdivided into condominiums or apartments.
Residual oil means crude oil, fuel oil that does not comply with
the specifications under the definition of distillate oil, and all fuel
oil numbers 4, 5, and 6, as defined by the American Society of Testing
and Materials in ASTM D396-10 (incorporated by reference, see Sec.
63.14(b)).
* * * * *
Seasonal boiler means a boiler that undergoes a shutdown for a
period of at least 7 consecutive months (or 210 consecutive days) each
12-month period due to seasonal conditions, except for periodic
testing. Periodic testing shall not exceed a combined total of 15 days
during the 7-month shutdown. This definition only applies to boilers
that would otherwise be included in the biomass subcategory or the oil
subcategory.
Shutdown means the cessation of operation of a boiler for any
purpose. Shutdown begins either when none of the steam or heat from the
boiler is supplied for heating and/or producing electricity, or for any
other purpose, or at the point of no fuel being fired in the boiler,
whichever is earlier. Shutdown ends when there is no steam and no heat
being supplied and no fuel being fired in the boiler.
Solid fossil fuel includes, but is not limited to, coal, coke,
petroleum coke, and tire-derived fuel.
[[Page 7517]]
Solid fuel means any solid fossil fuel or biomass or bio-based
solid fuel.
Startup means either the first-ever firing of fuel in a boiler for
the purpose of supplying steam or heat for heating and/or producing
electricity, or for any other purpose, or the firing of fuel in a
boiler after a shutdown event for any purpose. Startup ends when any of
the steam or heat from the boiler is supplied for heating and/or
producing electricity, or for any other purpose.
Temporary boiler means any gaseous or liquid fuel boiler that is
designed to, and is capable of, being carried or moved from one
location to another by means of, for example, wheels, skids, carrying
handles, dollies, trailers, or platforms. A boiler is not a temporary
boiler if any one of the following conditions exists:
(1) The equipment is attached to a foundation.
(2) The boiler or a replacement remains at a location within the
facility and performs the same or similar function for more than 12
consecutive months, unless the regulatory agency approves an extension.
An extension may be granted by the regulating agency upon petition by
the owner or operator of a unit specifying the basis for such a
request. Any temporary boiler that replaces a temporary boiler at a
location within the facility and performs the same or similar function
will be included in calculating the consecutive time period unless
there is a gap in operation of 12 months or more.
(3) The equipment is located at a seasonal facility and operates
during the full annual operating period of the seasonal facility,
remains at the facility for at least 2 years, and operates at that
facility for at least 3 months each year.
(4) The equipment is moved from one location to another within the
facility but continues to perform the same or similar function and
serve the same electricity, steam, and/or hot water system in an
attempt to circumvent the residence time requirements of this
definition.
Tune-up means adjustments made to a boiler in accordance with the
procedures outlined in Sec. 63.11223(b).
Vegetable oil means oils extracted from vegetation.
Voluntary Consensus Standards (VCS) mean technical standards (e.g.,
materials specifications, test methods, sampling procedures, business
practices) developed or adopted by one or more voluntary consensus
bodies. EPA/Office of Air Quality Planning and Standards, by precedent,
has only used VCS that are written in English. Examples of VCS bodies
are: American Society of Testing and Materials (ASTM 100 Barr Harbor
Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959,
(800) 262-1373, http://www.astm.org), American Society of Mechanical
Engineers (ASME ASME, Three Park Avenue, New York, NY 10016-5990, (800)
843-2763, http://www.asme.org), International Standards Organization
(ISO 1, ch. de la Voie-Creuse, Case postale 56, CH-1211 Geneva 20,
Switzerland, +41 22 749 01 11, http://www.iso.org/iso/home.htm),
Standards Australia (AS Level 10, The Exchange Centre, 20 Bridge
Street, Sydney, GPO Box 476, Sydney NSW 2001, + 61 2 9237 6171 http://www.stadards.org.au), British Standards Institution (BSI, 389 Chiswick
High Road, London, W4 4AL, United Kingdom, +44 (0)20 8996 9001, http://www.bsigroup.com), Canadian Standards Association (CSA 5060 Spectrum
Way, Suite 100, Mississauga, Ontario L4W 5N6, Canada, 800-463-6727,
http://www.csa.ca), European Committee for Standardization (CEN CENELEC
Management Centre Avenue Marnix 17 B-1000 Brussels, Belgium +32 2 550
08 11, http://www.cen.eu/cen), and German Engineering Standards (VDI
VDI Guidelines Department, P.O. Box 10 11 39 40002, Duesseldorf,
Germany, +49 211 6214-230, http://www.vdi.eu). The types of standards
that are not considered VCS are standards developed by: the United
States, e.g., California (CARB) and Texas (TCEQ); industry groups, such
as American Petroleum Institute (API), Gas Processors Association
(GPA), and Gas Research Institute (GRI); and other branches of the U.S.
government, e.g., Department of Defense (DOD) and Department of
Transportation (DOT). This does not preclude EPA from using standards
developed by groups that are not VCS bodies within their rule. When
this occurs, EPA has done searches and reviews for VCS equivalent to
these non-EPA methods.
Waste heat boiler means a device that recovers normally unused
energy (i.e., hot exhaust gas) and converts it to usable heat. Waste
heat boilers are also referred to as heat recovery steam generators.
Waste heat boilers are heat exchangers generating steam from incoming
hot exhaust gas from an industrial (e.g., thermal oxidizer, kiln,
furnace) or power (e.g., combustion turbine, engine) equipment. Duct
burners are sometimes used to increase the temperature of the incoming
hot exhaust gas.
Wet scrubber means any add-on air pollution control device that
mixes an aqueous stream or slurry with the exhaust gases from a boiler
to control emissions of particulate matter or to absorb and neutralize
acid gases, such as hydrogen chloride. A wet scrubber creates an
aqueous stream or slurry as a byproduct of the emissions control
process.
* * * * *
0
21. Table 1 to subpart JJJJJJ is revised to read as follows:
As stated in Sec. 63.11201, you must comply with the following
applicable emission limits:
Table 1 to Subpart JJJJJJ of Part 63--Emission Limits
------------------------------------------------------------------------
You must achieve less
than or equal to the
For the following following emission
If your boiler is in this pollutants . . . limits, except during
subcategory . . . periods of startup
and shutdown . . .
------------------------------------------------------------------------
1. New coal-fired boilers with a. PM 3.0E-02 pounds(lb)
heat input capacity of 30 (Filterable). per million British
million British thermal units b. Mercury....... thermal units
per hour (MMBtu/hr) or c. CO............ (MMBtu) of heat
greater that do not meet the input.
definition of limited-use 2.2E-05 lb per MMBtu
boiler. of heat input.
420 parts per million
(ppm) by volume on a
dry basis corrected
to 3 percent oxygen
(3-run average or 10-
day rolling
average).
2. New coal-fired boilers with a. PM 4.2E-01 lb per MMBtu
heat input capacity of (Filterable). of heat input.
between 10 and 30 MMBtu/hr b. Mercury....... 2.2E-05 lb per MMBtu
that do not meet the c. CO............ of heat input.
definition of limited-use 420 ppm by volume on
boiler. a dry basis
corrected to 3
percent oxygen (3-
run average or 10-
day rolling
average).
[[Page 7518]]
3. New biomass-fired boilers PM (Filterable).. 3.0E-02 lb per MMBtu
with heat input capacity of of heat input.
30 MMBtu/hr or greater that
do not meet the definition of
seasonal boiler or limited-
use boiler.
4. New biomass fired boilers PM (Filterable).. 7.0E-02 lb per MMBtu
with heat input capacity of of heat input.
between 10 and 30 MMBtu/hr
that do not meet the
definition of seasonal boiler
or limited-use boiler.
5. New oil-fired boilers with PM (Filterable).. 3.0E-02 lb per MMBtu
heat input capacity of 10 of heat input.
MMBtu/hr or greater that do
not meet the definition of
seasonal boiler or limited-
use boiler.
6. Existing coal-fired boilers a. Mercury....... 2.2E-05 lb per MMBtu
with heat input capacity of b. CO............ of heat input.
10 MMBtu/hr or greater that 420 ppm by volume on
do not meet the definition of a dry basis
limited-use boiler. corrected to 3
percent oxygen.
------------------------------------------------------------------------
0
22. Table 2 to subpart JJJJJJ is revised to read as follows:
As stated in Sec. 63.11201, you must comply with the following
applicable work practice standards, emission reduction measures, and
management practices:
Table 2 to Subpart JJJJJJ of Part 63--Work Practice Standards, Emission
Reduction Measures, and Management Practices
------------------------------------------------------------------------
If your boiler is in this
subcategory . . . You must meet the following . . .
------------------------------------------------------------------------
1. Existing or new coal- Minimize the boiler's startup and
fired, new biomass-fired, or shutdown periods and conduct startups
new oil-fired boilers (units and shutdowns according to the
with heat input capacity of manufacturer's recommended procedures.
10 MMBtu/hr or greater). If manufacturer's recommended procedures
are not available, you must follow
recommended procedures for a unit of
similar design for which manufacturer's
recommended procedures are available.
2. Existing coal-fired Conduct an initial tune-up as specified
boilers with heat input in Sec. 63.11214, and conduct a tune-
capacity of less than 10 up of the boiler biennially as specified
MMBtu/hr that do not meet in Sec. 63.11223.
the definition of limited-
use boiler, or use an oxygen
trim system that maintains
an optimum air-to-fuel ratio.
3. New coal-fired boilers Conduct a tune-up of the boiler
with heat input capacity of biennially as specified in Sec.
less than 10 MMBtu/hr that 63.11223.
do not meet the definition
of limited-use boiler, or
use an oxygen trim system
that maintains an optimum
air-to-fuel ratio.
4. Existing oil-fired boilers Conduct an initial tune-up as specified
with heat input capacity in Sec. 63.11214, and conduct a tune-
greater than 5 MMBtu/hr that up of the boiler biennially as specified
do not meet the definition in Sec. 63.11223.
of seasonal boiler or
limited-use boiler, or use
an oxygen trim system that
maintains an optimum air-to-
fuel ratio.
5. New oil-fired boilers with Conduct a tune-up of the boiler
heat input capacity greater biennially as specified in Sec.
than 5 MMBtu/hr that do not 63.11223.
meet the definition of
seasonal boiler or limited-
use boiler, or use an oxygen
trim system that maintains
an optimum air-to-fuel ratio.
6. Existing biomass-fired Conduct an initial tune-up as specified
boilers that do not meet the in Sec. 63.11214, and conduct a tune-
definition of seasonal up of the boiler biennially as specified
boiler or limited-use in Sec. 63.11223.
boiler, or use an oxygen
trim system that maintains
an optimum air-to-fuel ratio.
7. New biomass-fired boilers Conduct a tune-up of the boiler
that do not meet the biennially as specified in Sec.
definition of seasonal 63.11223.
boiler or limited-use
boiler, or use an oxygen
trim system that maintains
an optimum air-to-fuel ratio.
8. Existing seasonal boilers. Conduct an initial tune-up as specified
in Sec. 63.11214, and conduct a tune-
up of the boiler every 5 years as
specified in Sec. 63.11223.
9. New seasonal boilers...... Conduct a tune-up of the boiler every 5
years as specified in Sec. 63.11223.
10. Existing limited-use Conduct an initial tune-up as specified
boilers. in Sec. 63.11214, and conduct a tune-
up of the boiler every 5 years as
specified in Sec. 63.11223.
11. New limited-use boilers.. Conduct a tune-up of the boiler every 5
years as specified in Sec. 63.11223.
12. Existing oil-fired Conduct an initial tune-up as specified
boilers with heat input in Sec. 63.11214, and conduct a tune-
capacity of equal to or less up of the boiler every 5 years as
than 5 MMBtu/hr. specified in Sec. 63.11223.
13. New oil-fired boilers Conduct a tune-up of the boiler every 5
with heat input capacity of years as specified in Sec. 63.11223.
equal to or less than 5
MMBtu/hr.
[[Page 7519]]
14. Existing coal-fired, Conduct an initial tune-up as specified
biomass-fired, or oil-fired in Sec. 63.11214, and conduct a tune-
boilers with an oxygen trim up of the boiler every 5 years as
system that maintains an specified in Sec. 63.11223.
optimum air-to-fuel ratio
that would otherwise be
subject to a biennial tune-
up.
15. New coal-fired, biomass- Conduct a tune-up of the boiler every 5
fired, or oil-fired boilers years as specified in Sec. 63.11223.
with an oxygen trim system
that maintains an optimum
air-to-fuel ratio that would
otherwise be subject to a
biennial tune-up.
16. Existing coal-fired, Must have a one-time energy assessment
biomass-fired, or oil-fired performed by a qualified energy
boilers (units with heat assessor. An energy assessment completed
input capacity of 10 MMBtu/ on or after January 1, 2008, that meets
hr and greater), not or is amended to meet the energy
including limited-use assessment requirements in this table
boilers. satisfies the energy assessment
requirement. Energy assessor approval
and qualification requirements are
waived in instances where past or
amended energy assessments are used to
meet the energy assessment requirements.
A facility that operates under an energy
management program compatible with ISO
50001 that includes the affected units
also satisfies the energy assessment
requirement. The energy assessment must
include the following with extent of the
evaluation for items (1) to (4)
appropriate for the on-site technical
hours listed in Sec. 63.11237:
(1) A visual inspection of the boiler
system,
(2) An evaluation of operating
characteristics of the affected boiler
systems, specifications of energy use
systems, operating and maintenance
procedures, and unusual operating
constraints,
(3) An inventory of major energy use
systems consuming energy from affected
boiler(s) and which are under control of
the boiler owner or operator,
(4) A review of available architectural
and engineering plans, facility
operation and maintenance procedures and
logs, and fuel usage,
(5) A list of major energy conservation
measures that are within the facility's
control,
(6) A list of the energy savings
potential of the energy conservation
measures identified, and
(7) A comprehensive report detailing the
ways to improve efficiency, the cost of
specific improvements, benefits, and the
time frame for recouping those
investments.
------------------------------------------------------------------------
0
23.Table 3 to subpart JJJJJJ is revised to read as follows:
As stated in Sec. 63.11201, you must comply with the applicable
operating limits:
Table 3 to Subpart JJJJJJ of Part 63--Operating Limits for Boilers With
Emission Limits
------------------------------------------------------------------------
If you demonstrate compliance You must meet these operating limits
with applicable emission except during periods of startup and
limits using . . . shutdown . . .
------------------------------------------------------------------------
1. Fabric filter control..... a. Maintain opacity to less than or equal
to 10 percent opacity (daily block
average); OR
b. Install and operate a bag leak
detection system according to Sec.
63.11224 and operate the fabric filter
such that the bag leak detection system
alarm does not sound more than 5 percent
of the operating time during each 6-
month period.
2. Electrostatic precipitator a. Maintain opacity to less than or equal
control. to 10 percent opacity (daily block
average); OR
b. Maintain the 30-day rolling average
total secondary electric power of the
electrostatic precipitator at or above
the minimum total secondary electric
power as defined in Sec. 63.11237.
3. Wet scrubber control...... Maintain the 30-day rolling average
pressure drop across the wet scrubber at
or above the minimum scrubber pressure
drop as defined in Sec. 63.11237 and
the 30-day rolling average liquid flow
rate at or above the minimum scrubber
liquid flow rate as defined in Sec.
63.11237.
4. Dry sorbent or activated Maintain the 30-day rolling average
carbon injection control. sorbent or activated carbon injection
rate at or above the minimum sorbent
injection rate or minimum activated
carbon injection rate as defined in Sec.
63.11237. When your boiler operates at
lower loads, multiply your sorbent or
activated carbon injection rate by the
load fraction (e.g., actual heat input
divided by the heat input during the
performance stack test; for 50 percent
load, multiply the injection rate
operating limit by 0.5).
5. Any other add-on air This option is for boilers that operate
pollution control type.. dry control systems. Boilers must
maintain opacity to less than or equal
to 10 percent opacity (daily block
average).
6. Fuel analysis............. Maintain the fuel type or fuel mixture
(annual average) such that the mercury
emission rate calculated according to
Sec. 63.11211(c) are less than the
applicable emission limit for mercury.
7. Performance stack testing. For boilers that demonstrate compliance
with a performance stack test, maintain
the operating load of each unit such
that it does not exceed 110 percent of
the average operating load recorded
during the most recent performance stack
test.
8. Oxygen analyzer system.... For boilers subject to a CO emission
limit that demonstrate compliance with
an oxygen analyzer system as specified
in Sec. 63.11224(a), maintain the 30-
day rolling average oxygen level at or
above the minimum oxygen level as
defined in Sec. 63.11237. This
requirement does not apply to units that
install an oxygen trim system since
these units will set the trim system to
the level specified in Sec.
63.11224(a)(7).
------------------------------------------------------------------------
[[Page 7520]]
* * * * *
0
24. Table 6 to subpart JJJJJJ is revised to read as follows:
As stated in Sec. 63.11211, you must comply with the following
requirements for establishing operating limits:
Table 6 to Subpart JJJJJJ of Part 63--Establishing Operating Limits
--------------------------------------------------------------------------------------------------------------------------------------------------------
And your operating
If you have an applicable limits are based on . . You must . . . Using . . . According to the following
emission limit for . . . . requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
1. PM or mercury............. a. Wet scrubber Establish site-specific Data from the pressure drop (a) You must collect pressure drop
operating parameters. minimum scrubber pressure and liquid flow rate and liquid flow rate data every 15
drop and minimum scrubber monitors and the PM or minutes during the entire period of
liquid flow rate operating mercury performance stack the performance stack tests;
limits according to Sec. tests.
63.11211(b).
(b) Determine the average pressure
drop and liquid flow rate for each
individual test run in the three-run
performance stack test by computing
the average of all the 15-minute
readings taken during each test run.
b. Electrostatic Establish a site-specific Data from the secondary (a) You must collect secondary
precipitator operating minimum total secondary electric power monitors electric power data every 15 minutes
parameters. electric power operating and the PM or mercury during the entire period of the
limit according to Sec. performance stack tests. performance stack tests;
63.11211(b).
(b) Determine the average total
secondary electric power for each
individual test run in the three-run
performance stack test by computing
the average of all the 15-minute
readings taken during each test run.
2. Mercury................... Dry sorbent or Establish a site-specific Data from the sorbent or (a) You must collect sorbent or
activated carbon minimum sorbent or activated carbon injection activated carbon injection rate data
injection rate activated carbon injection rate monitors and the every 15 minutes during the entire
operating parameters. rate operating limit mercury performance stack period of the performance stack
according to Sec. tests. tests;
63.11211(b).
(b) Determine the average sorbent or
activated carbon injection rate for
each individual test run in the
three-run performance stack test by
computing the average of all the 15-
minute readings taken during each
test run.
(c) When your unit operates at lower
loads, multiply your sorbent or
activated carbon injection rate by
the load fraction (e.g., actual heat
input divided by heat input during
performance stack test, for 50
percent load, multiply the injection
rate operating limit by 0.5) to
determine the required injection
rate.
3. CO........................ Oxygen................. Establish a unit-specific Data from the oxygen (a) You must collect oxygen data
limit for minimum oxygen analyzer system specified every 15 minutes during the entire
level. in Sec. 63.11224(a). period of the performance stack
tests;
(b) Determine the average hourly
oxygen concentration for each
individual test run in the three-run
performance stack test by computing
the average of all the 15-minute
readings taken during each test run.
4. Any pollutant for which Boiler operating load.. Establish a unit-specific Data from the operating (a) You must collect operating load
compliance is demonstrated limit for maximum operating load monitors (fuel feed data (fuel feed rate or steam
by a performance stack test. load according to Sec. monitors or steam generation data) every 15 minutes
63.11212(c). generation monitors). during the entire period of the
performance test.
(b) Determine the average operating
load by computing the hourly
averages using all of the 15-minute
readings taken during each
performance test.
(c) Determine the average of the
three test run averages during the
performance test, and multiply this
by 1.1 (110 percent) as your
operating limit.
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 7521]]
0
25. Table 7 to subpart JJJJJJ is revised to read as follows:
As stated in Sec. 63.11222, you must show continuous compliance
with the emission limitations for each boiler according to the
following:
Table 7 to Subpart JJJJJJ of Part 63--Demonstrating Continuous
Compliance
------------------------------------------------------------------------
If you must meet the
following operating limits . You must demonstrate continuous
. . compliance by . . .
------------------------------------------------------------------------
1. Opacity................... a. Collecting the opacity monitoring
system data according to Sec.
63.11224(e) and Sec. 63.11221; and
b. Reducing the opacity monitoring data
to 6-minute averages; and
c. Maintaining opacity to less than or
equal to 10 percent (daily block
average).
2. Fabric Filter Bag Leak Installing and operating a bag leak
Detection Operation. detection system according to Sec.
63.11224(f) and operating the fabric
filter such that the requirements in
Sec. 63.11222(a)(4) are met.
3. Wet Scrubber Pressure Drop a. Collecting the pressure drop and
and Liquid Flow Rate. liquid flow rate monitoring system data
according to Sec. Sec. 63.11224 and
63.11221; and
b. Reducing the data to 30-day rolling
averages; and
c. Maintaining the 30-day rolling average
pressure drop and liquid flow rate at or
above the minimum pressure drop and
minimum liquid flow rate according to
Sec. 63.11211.
4. Dry Scrubber Sorbent or a. Collecting the sorbent or activated
Activated Carbon Injection carbon injection rate monitoring system
Rate. data for the dry scrubber according to
Sec. Sec. 63.11224 and 63.11221; and
b. Reducing the data to 30-day rolling
averages; and
c. Maintaining the 30-day rolling average
sorbent or activated carbon injection
rate at or above the minimum sorbent or
activated carbon injection rate
according to Sec. 63.11211.
5. Electrostatic Precipitator a. Collecting the total secondary
Total Secondary Electric electric power monitoring system data
Power. for the electrostatic precipitator
according to Sec. Sec. 63.11224 and
63.11221; and
b. Reducing the data to 30-day rolling
averages; and
c. Maintaining the 30-day rolling average
total secondary electric power at or
above the minimum total secondary
electric power according to Sec.
63.11211.
6. Fuel Pollutant Content.... a. Only burning the fuel types and fuel
mixtures used to demonstrate compliance
with the applicable emission limit
according to Sec. 63.11213 as
applicable; and
b. Keeping monthly records of fuel use
according to Sec. Sec. 63.11222(a)(2)
and 63.11225(b)(4).
7. Oxygen content............ a. Continuously monitoring the oxygen
content of flue gas according to Sec.
63.11224 (This requirement does not
apply to units that install an oxygen
trim system since these units will set
the trim system to the level specified
in Sec. 63.11224(a)(7)); and
b. Reducing the data to 30-day rolling
averages; and
c. Maintaining the 30-day rolling average
oxygen content at or above the minimum
oxygen level established during the most
recent CO performance test.
8. CO emissions.............. a. Continuously monitoring the CO
concentration in the combustion exhaust
according to Sec. Sec. 63.11224 and
63.11221; and
b. Correcting the data to 3 percent
oxygen, and reducing the data to 1-hour
averages; and
c. Reducing the data from the hourly
averages to 10-day rolling averages; and
d. Maintaining the 10-day rolling average
CO concentration at or below the
applicable emission limit in Table 1 to
this subpart.
9. Boiler operating load..... a. Collecting operating load data (fuel
feed rate or steam generation data)
every 15 minutes; and
b. Reducing the data to 30-day rolling
averages; and
c. Maintaining the 30-day rolling average
at or below the operating limit
established during the performance test
according to Sec. 63.11212(c) and
Table 6 to this subpart.
------------------------------------------------------------------------
0
26. Table 8 to subpart JJJJJJ is amended by:
0
a. Revising the entry for ``Sec. 63.9''.
0
b. Revising the entry for ``Sec. 63.10(e) and (f)''.
0
c. Adding an entry for ``Sec. 63.10(f)''.
The revisions read as follows:
* * * * *
[[Page 7522]]
Table 8 to Subpart JJJJJJ of Part 63--Applicability of General Provisions to Subpart JJJJJJ
----------------------------------------------------------------------------------------------------------------
General provisions cite Subject Does it apply?
----------------------------------------------------------------------------------------------------------------
* * * * * * *
Sec. 63.9........................ Notification Requirements............ Yes, excluding the information
required in Sec.
63.9(h)(2)(i)(B), (D), (E) and (F).
See Sec. 63.11225.
* * * * * * *
Sec. 63.10(e).................... Additional reporting requirements for Yes.
sources with CMS.
Sec. 63.10(f).................... Waiver of recordkeeping or reporting Yes.
requirements.
* * * * * * *
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[FR Doc. 2012-31645 Filed 1-31-13; 8:45 am]
BILLING CODE 6560-50-P